Edgar Filing: DYNEGY INC.

DYN-2013.3.31-10Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2013

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

For the transition period from ________ to ________

Commission file number: 001-33443

DYNEGY INC.

(Exact name of registrant as specified in its charter)



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

601 Travis, Suite 1400
Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

(713) 507-6400

(Registrant’s telephone number, including area code)

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

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 ¨

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 ý
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 ¨ No x

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Indicate by check mark whether the registrant filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes x No ¨

Indicate the number of shares outstanding of our class of common stock, as of the latest practicable date: Common stock, $0.01 par value per share, 99,999,196 shares outstanding as of April 23, 2013.

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TABLE OF CONTENTS



		Page
PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS:

Condensed Consolidated Balance Sheets:
March 31, 2013 and December 31, 2012		1
Condensed Consolidated Statements of Operations:
For the three months ended March 31, 2013 and 2012		3
Condensed Consolidated Statements of Comprehensive Loss:
For the three months ended March 31, 2013 and 2012		4
Condensed Consolidated Statements of Cash Flows:
For the three months ended March 31, 2013 and 2012		5
Notes to Condensed Consolidated Financial Statements		6

Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	30
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	54
Item 4.	CONTROLS AND PROCEDURES	55

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS	56
Item 1A.	RISK FACTORS	56
Item 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57
Item 6.	EXHIBITS	58

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DEFINITIONS

Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. Discussions or areas of this report that apply only to Dynegy, Legacy Dynegy or DH are clearly noted in such sections or areas and specific defined terms may be introduced for use only in those sections or areas. Further, as used in this Form 10-Q, the abbreviations contained herein have the meanings set forth below.



AEM		Ameren Energy Marketing Company
AER		Ameren Energy Resources Company, LLC
AERG		Ameren Energy Resources Generating Company
ARO		Asset retirement obligation
ASU		Accounting Standards Update
BTA		Best technology available
CAIR		Clean Air Interstate Rule
CAISO		The California Independent System Operator
CARB		California Air Resources Board
CCR		Coal Combustion Residuals
CEO		Chief Executive Officer
CFO		Chief Financial Officer
CFTC		U.S. Commodity Futures Trading Commission
CPUC		California Public Utility Commission
CRCG		Commodity Risk Control Group
CSAPR		Cross-State Air Pollution Rule
DCIH		Dynegy Coal Investments Holdings, LLC
DGIN		Dynegy Gas Investments, LLC
DH		Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DMG		Dynegy Midwest Generation, LLC
DMSLP		Dynegy Midstream Services L.P.
DPC		Dynegy Power, LLC
DYPM		Dynegy Power Marketing, LLC
EBITDA		Earnings before interest, taxes, depreciation and amortization
ELG		Effluent Limitation Guidelines
EMA		Energy Management Agency Services Agreement
EMT		Executive Management Team
EPA		Environmental Protection Agency
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
FTR		Financial Transmission Rights
GAAP		Generally Accepted Accounting Principles of the United States of America
GHG		Greenhouse Gas
IBEW		International Brotherhood of Electrical Workers
ICC		Illinois Commerce Commission
IMA		In-market asset availability
IPH		Illinois Power Holdings, LLC
IRS		Internal Revenue Service
ISO		Independent System Operator
ISO-NE		Independent System Operator New England
kW		Kilowatt
LC		Letter of Credit
LIBOR		London Interbank Offered Rate

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MISO		Midwest Independent Transmission System Operator, Inc.
MMBtu		One million British thermal units
MW		Megawatts
MWh		Megawatt hour
NM		Not Meaningful
NOL		Net operating loss
NPDES		National Pollutant Discharge Elimination System
NYISO		New York Independent System Operator
NYSE		New York Stock Exchange
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PRIDE		Producing Results through Innovation by Dynegy Employees
RFO		Request for offer
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
RPM		Reliability Pricing Model
RTO		Regional Transmission Organization
SCE		Southern California Edison
SEC		U.S. Securities and Exchange Commission
SO2		Sulfur dioxide
SPDES		State Pollutant Discharge Elimination System
VaR		Value at Risk
VLGC		Very Large Gas Carrier

iii

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions)



	March 31, 2013			December 31, 2012
ASSETS
Current Assets
Cash and cash equivalents	$	304		$	348
Restricted cash	98			98
Accounts receivable	87			108
Accounts receivable, affiliates	1			1
Inventory	93			101
Assets from risk-management activities	36			13
Assets from risk-management activities, affiliates	3			4
Broker margin account	34			40
Intangible assets	223			271
Prepayments and other current assets	77			59
Total Current Assets	956			1,043
Property, Plant and Equipment	3,062			3,064
Accumulated depreciation	(74		)	(42		)
Property, Plant and Equipment, Net	2,988			3,022
Other Assets
Restricted cash	224			237
Assets from risk-management activities	1			—
Intangible assets	51			71
Deferred income taxes	95			95
Other long-term assets	67			67
Total Assets	$	4,382		$	4,535

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



	March 31, 2013			December 31, 2012
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities
Accounts payable	$	95		$	112
Accounts payable, affiliates	1			1
Accrued interest	1			—
Deferred income taxes	95			95
Accrued liabilities and other current liabilities	75			85
Liabilities from risk-management activities	73			25
Current portion of long-term debt	29			29
Total Current Liabilities	369			347
Long-term debt	1,353			1,386
Other Liabilities
Liabilities from risk-management activities	43			42
Other long-term liabilities	254			257
Total Liabilities	$	2,019		$	2,032
Commitments and Contingencies (Note 13)

Stockholders’ Equity
Common Stock, $0.01 par value, 420,000,000 shares authorized and 99,999,196 shares issued and outstanding at March 31, 2013 and December 31, 2012, respectively	1			1
Additional paid-in capital	2,600			2,598
Accumulated other comprehensive loss, net of tax	11			11
Accumulated deficit	(249		)	(107		)
Total Stockholders’ Equity	$	2,363		$	2,503
Total Liabilities and Stockholders' Equity	$	4,382		$	4,535

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(unaudited) (in millions)



	Successor			Predecessor
	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Revenues	$	318		$	268
Cost of sales	(284		)	(180		)
Gross margin, exclusive of depreciation shown separately below	34			88
Operating and maintenance expense, exclusive of depreciation shown separately below	(71		)	(34		)
Depreciation and amortization expense	(54		)	(22		)
Gain on sale of assets, net	1			—
General and administrative expense	(22		)	(20		)
Acquisition and integration costs	(3		)	—
Operating income (loss)	(115		)	12
Bankruptcy reorganization items, net	(1		)	152
Interest expense	(28		)	(31		)
Impairment of Undertaking receivable, affiliate	—			(832		)
Other income and expense, net	2			24
Loss from continuing operations before income taxes	(142		)	(675		)
Income tax benefit (Note 15)	—			6
Loss from continuing operations	(142		)	(669		)
Loss from discontinued operations, net of tax	—			(413		)
Net loss	$	(142	)	$	(1,082	)

Loss Per Share (Note 17):
Basic loss per share:
Loss from continuing operations	$	(1.42	)	N/A
Loss from discontinued operations	—			N/A
Basic loss per share	$	(1.42	)	N/A

Diluted loss per share:
Loss from continuing operations	$	(1.42	)	N/A
Loss from discontinued operations	—			N/A
Diluted loss per share	$	(1.42	)	N/A

Basic shares outstanding	100			N/A
Diluted shares outstanding	100			N/A

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS

(unaudited) (in millions)



	Successor			Predecessor
	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Net loss	$	(142	)	$	(1,082	)
Amortization of unrecognized prior service cost and actuarial loss, net of tax	—			(1		)
Other comprehensive loss, net of tax	$	—		$	(1	)
Total comprehensive loss	$	(142	)	$	(1,083	)

See the notes to condensed consolidated financial statements.

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DYNEGY INC.

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



	Successor			Predecessor
	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(142	)	$	(1,082	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation and amortization	50			24
Amortization of intangibles	63			11
Bankruptcy reorganization items, net	—			228
Impairment of Undertaking receivable, affiliate	—			832
Risk-management activities	38			(41		)
Risk-management activities, affiliate	—			1
Gain on sale of assets, net	(1		)	—
Deferred income taxes	—			(6		)
Other	5			(1		)
Changes in working capital:
Accounts receivable	22			24
Inventory	8			(3		)
Broker margin account	(8		)	2
Prepayments and other current assets	(10		)	(107		)
Accounts payable and accrued liabilities	(26		)	7
Affiliate transactions	(1		)	(29		)
Changes in non-current assets	(4		)	(6		)
Changes in non-current liabilities	(1		)	1
Net cash used in operating activities	$	(7	)	$	(145	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(20		)	(9		)
Proceeds from asset sales, net	1			—
Decrease in restricted cash	13			148
Net cash provided by (used in) investing activities	$	(6	)	$	139
CASH FLOWS FROM FINANCING ACTIVITIES:
Payment of financing costs	(3		)	—
Repayments of borrowings	(28		)	(3		)
Net cash used in financing activities	$	(31	)	$	(3	)
Net decrease in cash and cash equivalents	(44		)	(9		)
Cash and cash equivalents, beginning of period	348			398
Cash and cash equivalents, end of period	$	304		$	389

See the notes to condensed consolidated financial statements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

EXPLANATORY NOTE

On September 30, 2012, pursuant to the terms of the Joint Chapter 11 Plan of Reorganization (the “Plan”) for Dynegy Holdings, LLC (“DH”) and Dynegy Inc. (“Dynegy”), DH merged with and into Dynegy, with Dynegy continuing as the surviving legal entity (the “Merger”). As described below in Note 1—Basis of Presentation and Organization, the accounting treatment of the Merger was reflected as a recapitalization of DH and, similar to a reverse merger, DH was the surviving accounting entity for financial reporting purposes. Therefore, our historical results for periods prior to the Merger are the same as DH’s historical results; accordingly, we refer to Dynegy as “Legacy Dynegy” for periods prior to the Merger.

On September 10, 2012, the Bankruptcy Court (as defined and discussed below in Note 4—Chapter 11 Cases) entered an order confirming the Plan and on October 1, 2012, (the “Plan Effective Date”), we consummated our reorganization under Chapter 11 pursuant to the Plan and Dynegy exited bankruptcy. As a result of the application of fresh-start accounting as of the Plan Effective Date, the financial statements on or prior to October 1, 2012 are not comparable with the financial statements after October 1, 2012. References to “Successor” refer to the Company after October 1, 2012, after giving effect to the application of fresh-start accounting. References to “Predecessor” refer to the Company on or prior to October 1, 2012. Additionally, on the Plan Effective Date, the DNE Debtor Entities (as defined and discussed below in Note 4—Chapter 11 Cases) did not emerge from bankruptcy; therefore, we deconsolidated our investment in these entities as of October 1, 2012. Accordingly, the results of operations of the DNE Debtor Entities are presented in discontinued operations for all periods presented.

Note 1—Basis of Presentation and Organization

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end condensed consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. The unaudited condensed consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2012, filed with the SEC on March 14, 2013, which we refer to as our “Form 10-K.”

Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as two segments in our consolidated financial statements: (i) the Coal segment (“Coal”) and (ii) the Gas segment (“Gas”). Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and depreciation and amortization expense. Please read Note 18—Segment Information for further discussion.

The Gas segment includes Dynegy Power, LLC (“DPC”), which owns, directly and indirectly, substantially all of our wholly-owned natural gas-fired power generation facilities.

The Coal segment includes Dynegy Midwest Generation, LLC (“DMG”), which owns, directly and indirectly, substantially all of our coal-fired power generation facilities. On September 1, 2011, DH sold 100 percent of the outstanding membership interests of Dynegy Coal Holdco, LLC (“Coal Holdco”) to Legacy Dynegy (the “DMG Transfer”). Therefore, the results of our Coal segment are not included in our consolidated results as of, and for the three months ended March 31, 2012. On June 5, 2012, DH reacquired Coal Holdco (including its subsidiary, DMG) from Legacy Dynegy (the “DMG Acquisition”). Please read Note 3—Acquisitions—DMG Acquisition for further discussion.

Merger. On September 30, 2012, pursuant to the terms of the Plan, DH merged with and into Legacy Dynegy, with Legacy Dynegy continuing as the surviving legal entity in the Merger. Immediately prior to the Merger, Legacy Dynegy had no substantive operations as our power generation facilities were operated through subsidiaries of DH. Further, as a result of the DH Chapter 11 Cases (as defined in Note 4—Chapter 11 Cases) in 2011, under applicable accounting standards, Dynegy was no longer deemed to have a controlling financial interest in DH and its wholly-owned subsidiaries; therefore, DH and its consolidated subsidiaries were no longer consolidated in Dynegy's consolidated financial statements as of November 7, 2011. As a result of these factors, the Merger was accounted for in a manner similar to a reverse merger, whereby DH is the surviving accounting entity for financial reporting purposes.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Prior to the Merger, DH was organized as a limited liability company and the capital structure of DH did not change until September 30, 2012. Although Legacy Dynegy’s shares were publicly traded, DH did not have any publicly traded shares prior to the Merger; therefore, no earnings (loss) per share is presented on our unaudited condensed consolidated statement of operations for the three months ended March 31, 2012.

Fresh-Start Accounting. On the Plan Effective Date, we applied “fresh-start accounting.” Fresh-start accounting requires us to allocate the reorganization value to our assets and liabilities in a manner similar to that which is required using the acquisition method of accounting for a business combination. Under the provisions of fresh-start accounting, a new entity has been created for financial reporting purposes. The financial statements of the Predecessor include the impact of the Plan provisions and the application of fresh-start accounting. As such, our financial information for the Successor is presented on a basis different from, and is therefore not comparable to, our financial information for the Predecessor for the period ended and as of October 1, 2012 or for prior periods. For further information, please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting in our Form 10-K.

Note 2—Accounting Policies

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures and other factors.

Accounting Principles Adopted During the Current Period

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. In February 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-02—Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income. This new guidance requires entities to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, entities are required to present significant amounts reclassified out of other comprehensive income by the respective line items of net income if the amount is reclassified in its entirety. ASU 2013-02 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. Please read Note 8—Accumulated Other Comprehensive Income for further discussion.

Disclosures about Offsetting Assets and Liabilities. In December 2011, the FASB issued ASU 2011-11—Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. This new guidance requires entities to disclose both gross and net information about instruments and transactions eligible for offsetting in the statement of financial position, as well as instruments and transactions subject to an agreement similar to a master netting arrangement. ASU 2011-11 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2012. Please read Note 6—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Note 3—Acquisitions

AER Transaction Agreement. On March 14, 2013, Illinois Power Holdings, LLC (“IPH”), an indirect wholly-owned subsidiary of Dynegy, entered into a definitive agreement (the “AER Transaction Agreement”) with Ameren Corporation (“Ameren”) pursuant to which IPH will, subject to the terms and conditions in the AER Transaction Agreement, acquire from Ameren 100 percent of the equity interest of Ameren Energy Resources Company, LLC (“AER”) (or, following a pre-closing reorganization contemplated by Ameren, a successor thereto) for no cash consideration (the “AER Acquisition”). AER and its subsidiaries consist of Ameren's merchant generation and its wholesale and retail marketing business. Pursuant to the AER Transaction Agreement, IPH will indirectly acquire AER's subsidiaries, including (i) Ameren Energy Generating Company (“Genco”), (ii) Ameren Energy Resources Generating Company (“AERG”) and (iii) Ameren Energy Marketing Company (“AEM”). We have provided a limited guaranty of certain obligations of IPH up to $25 million (the “Limited Guaranty”) as described below.

The transaction does not include AER's gas-fired power generation facilities: Elgin, Gibson City and Grand Tower (the “Put Assets”). Prior to signing the AER Transaction Agreement, AERG, Genco and Ameren Energy Medina Valley Cogen L.L.C. (“Medina Valley”), an affiliate of AER that IPH will not be acquiring in the transaction, entered into an amendment to a

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

put option agreement (the “Put Option Agreement”), dated as of March 28, 2012, whereby the Put Assets will be sold by Genco, subject to approval by FERC, to Medina Valley for a minimum of $133 million (the “Put Transaction”). New appraisals will be obtained for the Put Assets prior to closing, and if the average value of the appraisals exceeds $133 million, any excess amount will be remitted to Genco. Further, in the event Ameren sells the Put Assets within two years of closing, Ameren will pay to Genco any after-tax proceeds in excess of $133 million, or the higher appraised value, if applicable. The minimum amount of $133 million is based on an average of three appraisals obtained in October 2012. The amount may increase as a result of new appraisals, but can not be reduced.

In connection with the transaction, Ameren will retain certain historical obligations of AER and its subsidiaries, including certain historical environmental and tax liabilities. Genco's approximately $825 million of notes will remain outstanding as an obligation of Genco. The debt bears interest at rates from 6.30 percent to 7.95 percent and matures between 2018 and 2032.

In connection with the transaction, Ameren is required at closing to ensure that a minimum of $93 million of cash is available at AER and its subsidiaries of which $70 million will be held at Genco plus the proceeds of the Put Transaction described above.

The AER Transaction Agreement includes customary representations, warranties and covenants by the parties. The closing of the transaction is expected to occur during the fourth quarter of 2013 and is subject to customary conditions, including (i) consummation of the Put Transaction under the Put Option Agreement; (ii) approval of FERC under Section 203 of the Federal Power Act, as amended (“FERC Approval”); (iii) approval of certain license transfers by the Federal Communications Commission; (iv) approval by the Illinois Pollution Control Board of the transfer to IPH of AER's air variance, which granted to AER a temporary exemption for the coal plants of its subsidiaries from certain air pollution limitations under Illinois law; (v) no injunction or other orders preventing the consummation of the transactions under the AER Transaction Agreement; (vi) the continuing accuracy of each party's representations and warranties; and (vii) the satisfaction of other customary conditions. Each party has agreed to indemnify the other for breaches of representations and warranties, breaches of covenants and certain other matters, subject to certain exceptions. The AER Transaction Agreement contains certain termination rights for both IPH and Ameren, including if the closing does not occur within 12 months following the date of the AER Transaction Agreement (subject to extension to 13 months in certain circumstances, if necessary in order to obtain FERC approval).

The AER Transaction Agreement provides for the payment of a termination fee by each party under specific circumstances. In certain circumstances, including failure to receive FERC Approval, IPH must pay a termination fee of $25 million to Ameren.

Concurrently with the execution of the AER Transaction Agreement, we entered into the Limited Guaranty, capped at $25 million in favor of Ameren, pursuant to which we will guaranty payout by IPH of any required termination fee and, for a period of two years after the closing (subject to certain exceptions), up to $25 million with respect to IPH's indemnification obligations and certain reimbursement obligations under the AER Transaction Agreement.

DMG Acquisition. On June 5, 2012, pursuant to a settlement agreement entered into with certain of DH's creditors, Legacy Dynegy and DH consummated the DMG Acquisition. The DMG Acquisition was accounted for as a business combination in DH's financial statements as Legacy Dynegy deconsolidated DH, effective November 7, 2011, as a result of the DH Chapter 11 Cases. Accordingly, the assets acquired and liabilities assumed were recognized at their fair value as of the acquisition date.

The purchase price was approximately $466 million. Consideration given by DH consisted of (i) approximately $402 million for the fair value of the Undertaking receivable, affiliate that was extinguished in connection with the transaction and (ii) approximately $64 million for the fair value of the Administrative Claim issued to Legacy Dynegy in the DH Chapter 11 Cases. As a result of entering into the Settlement Agreement, the Undertaking receivable was impaired to $418 million as of March 31, 2012, resulting in a charge of approximately $832 million. The carrying value of the Undertaking was adjusted to the value received in the DMG Acquisition plus interest payments received subsequent to March 31, 2012.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Pro Forma Results. The unaudited pro forma financial results for the three months ended March 31, 2012 show the effect of the DMG Acquisition as if the acquisition had occurred as of January 1, 2012.



	Predecessor
(amounts in millions)	Three Months Ended March 31, 2012
Revenues	$	445
Loss from continuing operations	$	(689	)
Loss from discontinued operations	$	(413	)
Net loss	$	(1,102	)

Note 4—Chapter 11 Cases

On November 7, 2011, DH and four of its wholly-owned subsidiaries, Dynegy Northeast Generation, Inc. (“DNE”), Hudson Power, L.L.C. (“Hudson”), Dynegy Danskammer, L.L.C. (“Danskammer”) and Dynegy Roseton, L.L.C. (“Roseton”, and together with DH, DNE, Hudson and Danskammer, the “DH Debtor Entities”) filed voluntary petitions (the “DH Chapter 11 Cases”) for relief under Chapter 11 of Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of New York, Poughkeepsie Division (the “Bankruptcy Court”). The DH Chapter 11 Cases were jointly administered for procedural purposes only. On July 6, 2012, Legacy Dynegy filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court (the “Dynegy Chapter 11 Case,” and together with the DH Chapter 11 Cases, the “Chapter 11 Cases”). Only Legacy Dynegy and the DH Debtor Entities filed voluntary petitions for relief under the Bankruptcy Code and none of our other direct or indirect subsidiaries are or were debtors thereunder.

On the Plan Effective Date, we consummated our reorganization under Chapter 11 pursuant to the Plan and Dynegy exited bankruptcy. DNE, Hudson, Danskammer and Roseton (the “DNE Debtor Entities”) remain in Chapter 11 bankruptcy and continue to operate their businesses as “debtors-in-possession” (the “DNE Bankruptcy Cases”). As a result, we deconsolidated the DNE Debtor Entities on the Plan Effective Date and have reported their results of operations as discontinued operations for all periods presented. Please read Note 5—Discontinued Operations and Note 10—Variable Interest Entities for further discussion.

For the three months ended and as of March 31, 2013, we do not have any subsidiaries under Chapter 11 protection included in our unaudited condensed consolidated financial statements. The condensed combined financial statements of the Debtor Entities included in our results for the three months ended March 31, 2012 are set forth below (amounts in millions):

Condensed Combined Statement of Operations of the Debtor Entities

For the Three Months Ended March 31, 2012



Revenues	$	—
Cost of sales	—
Operating expenses	—
General and administrative expenses	(2		)
Operating loss	(2		)
Bankruptcy reorganization items, net	152
Equity losses	(17		)
Impairment of Undertaking receivable, affiliate	(832		)
Other income and expense, net	24
Income tax benefit	6
Loss from continuing operations	(669		)
Loss from discontinued operations	(413		)
Net loss	$	(1,082	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Condensed Combined Statement of Cash Flows of the Debtor Entities

For the Three Months Ended March 31, 2012



Net cash used in:
Operating activities	$	(12	)
Investing activities	—
Financing activities	—
Net decrease in cash and cash equivalents	(12		)
Cash and cash equivalents, beginning of period	33
Cash and cash equivalents, end of period	$	21

Basis of Presentation. The condensed combined financial statements only include the financial statements of the DH Debtor Entities. Transactions among the DH Debtor Entities are eliminated in consolidation.

Interest Expense. The DH Debtor Entities discontinued recording interest on unsecured liabilities subject to compromise (“LSTC”) effective November 8, 2011. Contractual interest on LSTC not reflected in the condensed combined financial statements was approximately $71 million for the three months ended March 31, 2012.

Bankruptcy Reorganization Items, net. Bankruptcy reorganization items, net represent the direct and incremental costs of bankruptcy, such as professional fees, pre-petition liability claim adjustments and losses related to terminated contracts that are probable and can be estimated. Bankruptcy reorganization items, net, as shown in the condensed combined statement of operations above, consist of expense or income incurred or earned as a direct and incremental result of the bankruptcy filings.

The table below lists the significant items within this category for the three months ended March 31, 2012 (amounts in millions).



	Three Months Ended March 31, 2012
Adjustments of estimated allowable claims:
DNE Leases (1)	$	(395	)
Subordinated notes (2)	161
Write-off of note payable, affiliate (3)	10
Other	(4		)
Total adjustments for estimated allowable claims	(228		)
Professional fees (4)	(19		)
Total Bankruptcy reorganization items, net	(247		)
Bankruptcy reorganization items, net included in discontinued operations	399
Total Bankruptcy reorganization items, net in continuing operations	$	152

__________________________________________


(1)	Amount represents adjustments to our estimate of the probable allowed claim associated with the DNE leases as a result of entering into the Settlement Agreement.


(2)	The estimated allowable claims related to the Subordinated Capital Income Securities were adjusted in the second quarter 2012 based on the terms of the Settlement Agreement, as amended. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting in our Form 10-K for further discussion.


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


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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Note 5—Discontinued Operations

Discontinued Operations

The DNE Debtor Entities remain in Chapter 11 bankruptcy and continue to operate their businesses as “debtors-in-possession.” As a result, Dynegy deconsolidated the DNE Debtor Entities, effective October 1, 2012. The Bankruptcy Court has approved agreements to sell the Danskammer and Roseton facilities for a combined cash purchase price of $23 million and the assumption of certain liabilities (the “Facilities Sale Transactions”). On January 23, 2013, the Bankruptcy Court approved the DNE Disclosure Statement. On March 12, 2013, the Bankruptcy Court approved the Plan of Liquidation for the DNE Debtor Entities. On April 30, 2013, we completed the sale of the Roseton facility. The Danskammer facility sale is expected to close upon the satisfaction of certain closing conditions and the receipt of any necessary regulatory approvals. If the Danskammer facility sale is not successful, certain of the DNE Debtor Entities may be required to liquidate their remaining assets or convert the DNE Chapter 11 Cases to Chapter 7 liquidation under the Bankruptcy Code. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting and Note 6—Dispositions and Discontinued Operations in our Form 10-K for further discussion. The results of operations of DNE are reported as discontinued operations for all periods presented.

Summary. There were no operating results reported as discontinued operations for the three months ended March 31, 2013. The amounts in the table below reflect the operating results of the businesses reported as discontinued operations for the three months ended March 31, 2012:



	Predecessor
(amounts in millions)	Three Months Ended March 31, 2012
Revenues	$	7
Income (loss) from operations before taxes	$	(413	)
Income (loss) from operations after taxes	$	(413	)

Note 6—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our 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 and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to two- year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term.

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

Quantitative Disclosures Related to Financial Instruments and Derivatives

The following disclosures and tables present information concerning the impact of derivative instruments on our unaudited condensed consolidated balance sheets and statements of operations. In the table below, commodity contracts primarily consist of derivative contracts related to our power generation business that we have not designated as accounting hedges that are entered into for purposes of economically hedging future fuel requirements and sales commitments and securing commodity prices. We elect not to designate any of our derivatives as accounting hedges. As of March 31, 2013, our commodity derivatives were comprised of both purchases and sales of commodities. As of March 31, 2013, we had net purchases and sales of derivative contracts outstanding in the following quantities:

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012



Contract Type	Hedge Designation	Quantity		Unit of Measure	Net Fair Value
(amounts in millions)
Commodity contracts:
Electric energy (1)	Not designated	(31	)	MWh	$	(80	)
Natural gas (1)	Not designated	130		MMBtu	$	27
Heat rate derivatives	Not designated	(1)/10		MWh/MMBtu	$	3
Interest rate contracts:
Interest rate swaps	Not designated	1,100		Dollars	$	(46	)
Interest rate caps	Not designated	1,400		Dollars	$	—
Common stock warrants	Not designated	16		Warrants	$	(20	)

__________________________________________

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

Derivatives on the Balance Sheet. We execute a significant volume of transactions through futures clearing managers. Our daily cash payments (receipts) with 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, “Margin”). In addition to these transactions we execute through the futures clearing managers, we also execute transactions through multiple bilateral counterparties. Our transactions with these counterparties are collateralized using cash collateral (“Collateral”), letters of credit and first liens. We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement, where the right of offset exists. We also offset Margin and Collateral paid to or received from all counterparties against the fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. As a result, the consolidated balance sheet presents derivative assets and liabilities, as well as cash paid to or received from all counterparties against those positions, on a net basis.

The following tables present the fair value and balance sheet classification of derivatives in the unaudited condensed consolidated balance sheet as of March 31, 2013 and the consolidated balance sheet as of December 31, 2012 segregated by type of contract segregated by assets and liabilities.



			March 31, 2013
						Gross amounts offset in the balance sheet
Contract Type		Balance Sheet Location	Gross Fair Value (1)			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
	Commodity contracts	Assets from risk management activities	$	124		$	(87	)	$	—	$	37
	Commodity contracts, affiliates	Assets from risk management activities, affiliates	3			—			—		3
	Total derivative assets		$	127		$	(87	)	$	—	$	40

Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(177	)	$	87		$	20	$	(70	)
	Interest rate contracts	Liabilities from risk management activities	(46		)	—			—		(46		)
	Common stock warrants	Other long-term liabilities	(20		)	—			—		(20		)
	Total derivative liabilities		$	(243	)	$	87		$	20	$	(136	)
Total derivatives			$	(116	)	$	—		$	20	$	(96	)

___________________________


(1)	As of and during the three months ended March 31, 2013, there were no gross amounts available to be offset that were not offset in our unaudited condensed consolidated balance sheet.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012



			December 31, 2012
						Gross amounts offset in the balance sheet
Contract Type		Balance Sheet Location	Gross Fair Value (1)			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
	Commodity contracts	Assets from risk management activities	$	61		$	(48	)	$	—	$	13
	Commodity contracts, affiliates	Assets from risk management activities, affiliates	4			—			—		4
	Total derivative assets		$	65		$	(48	)	$	—	$	17

Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(77	)	$	48		$	8	$	(21	)
	Interest rate contracts	Liabilities from risk management activities	(46		)	—			—		(46		)
	Common stock warrants	Other long-term liabilities	(20		)	—			—		(20		)
	Total derivative liabilities		$	(143	)	$	48		$	8	$	(87	)
Total derivatives			$	(78	)	$	—		$	8	$	(70	)

___________________________


(1)	As of and during the year ended December 31, 2012, there were no gross amounts available to be offset that were not offset in our consolidated balance sheet.

The following table summarizes our cash collateral posted as of March 31, 2013 and December 31, 2012, along with the location on the balance sheet and the amount applied against our short-term risk management liabilities.



Location on balance sheet	March 31, 2013				December 31, 2012
Location on balance sheet	Collateral posted		Amount applied against short-term risk management liabilities		Collateral posted		Amount applied against short-term risk management liabilities
(amounts in millions)
Broker margin	$	51	$	17	$	44	$	4
Prepayments and other current assets	$	18	$	3	$	17	$	4

Impact of Derivatives on the Consolidated Statements of Operations

The following discussion and table presents the location and amount of gains and losses on derivative instruments in our consolidated statements of operations. We had no derivatives that were designated in qualifying hedging relationships during the three months ended March 31, 2013 and 2012.

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

For the three months ended March 31, 2013 and 2012, our Revenues included unrealized mark-to-market losses related to this activity of approximately $38 million and $43 million, respectively.

The realized and unrealized impact of derivative financial instruments on our unaudited condensed consolidated statements of operations for the three months ended March 31, 2013 and 2012 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 and interest payments are made.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012



		Successor			Predecessor
Derivatives Not Designated as Hedges	Location of Gain ( Loss) Recognized in Income on Derivatives	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
(amounts in millions)
Commodity contracts	Revenues	$	(34	)	$	8
Commodity contracts, affiliates	Revenues	$	(2	)	$	(6	)
Interest rate contracts	Interest Expense	$	—		$	3

Note 7—Fair Value Measurements

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. We have consistently used this valuation technique for all periods presented. Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements in our Form 10-K for further discussion.

The 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 March 31, 2013 and December 31, 2012 and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid. 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 March 31, 2013
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	47		$	12		$	59
Natural gas derivatives	—			65			—			65
Heat rate derivatives	—			—			3			3
Total assets from commodity risk management activities	$	—		$	112		$	15		$	127
Liabilities:										.
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(127	)	$	(12	)	$	(139	)
Natural gas derivatives	—			(38		)	—			(38		)
Total liabilities from commodity risk management activities	—			(165		)	(12		)	(177		)
Liabilities from interest rate contracts	—			(46		)	—			(46		)
Liabilities from outstanding common stock warrants	(20		)	—			—			(20		)
Total liabilities	$	(20	)	$	(211	)	$	(12	)	$	(243	)

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012



	Fair Value as of December 31, 2012
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	37		$	11		$	48
Natural gas derivatives	—			14			—			14
Heat rate derivatives	—			—			3			3
Total assets from commodity risk management activities	$	—		$	51		$	14		$	65
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(50	)	$	(6	)	$	(56	)
Natural gas derivatives	—			(20		)	—			(20		)
Heat rate derivatives	—			—			(1		)	(1		)
Total liabilities from commodity risk management activities	—			(70		)	(7		)	(77		)
Liabilities from interest rate contracts	—			(46		)	—			(46		)
Liabilities from outstanding common stock warrants	(20		)	—			—			(20		)
Total liabilities	$	(20	)	$	(116	)	$	(7	)	$	(143	)

Level 3 Valuation Methods. The electricity contracts classified within Level 3 are primarily financial swaps executed in illiquid trading locations, capacity contracts, heat rate derivatives and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. Additionally, FTRs are classified within the electricity contracts, which are also an illiquid product. The forward market price of FTRs is derived using historical congestion patterns within the marketplace. Heat rate derivative valuations are derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities and modeled power/natural gas correlation values.

Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measure of our commodity instruments categorized within Level 3 of the fair value hierarchy are estimates of future price correlation, future market volatility, estimates of forward congestion power price spreads and assumptions of illiquid power location pricing basis to liquid locations. These assumptions are generally independent of each other. Volatility curves and power price spreads are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price or volatility of the spread on a long/short position in isolation would result in a higher/lower fair value measurement. A 10 percent change in pricing inputs and changes in volatilities and correlation factors would result in less than a $1 million change in our Level 3 fair value. 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:



	Successor
	Three Months Ended March 31, 2013
(amounts in millions)	Electricity Derivatives			Heat Rate Derivatives		Total
Balance at December 31, 2012	$	5		$	2	$	7
Total gains included in earnings	—			1		1
Settlements (1)	(5		)	—		(5		)
Balance at March 31, 2013	$	—		$	3	$	3
Unrealized gains relating to instruments held as of March 31, 2013	$	—		$	1	$	1

__________________________________________

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012


(1)	For purposes of this table, we define settlements as the beginning of period fair value of contracts that settled during the period.



	Predecessor
	Three Months Ended March 31, 2012
(amounts in millions)	Electricity Derivatives			Heat Rate Derivatives			Interest Rate Swaps			Total
Balance at December 31, 2011	$	20		$	(17	)	$	(6	)	$	(3	)
Total gains (losses) included in earnings, net of affiliates	2			2			(3		)	1
Settlements, net of affiliates (1)	—			4			—			4
Balance at March 31, 2012	$	22		$	(11	)	$	(9	)	$	2
Unrealized losses relating to instruments (net of affiliates) held as of March 31, 2012	$	(1	)	$	—		$	(3	)	$	(4	)

__________________________________________


(1)	For purposes of this table, we define settlements as the beginning of period fair value of contracts that settled during the period.

Gains and losses (realized and unrealized) for Level 3 recurring items are included in Revenues and Interest expense, net on the unaudited condensed consolidated statements of operations for commodity derivatives and interest rate swaps, respectively. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any transfers between Level 1, Level 2 and Level 3 for the three months ended March 31, 2013 and 2012.

Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis 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.

We did not have any nonfinancial assets or liabilities measured at fair value on a non-recurring basis during the three months ended March 31, 2013.

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. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of March 31, 2013 and December 31, 2012, respectively.



	March 31, 2013						December 31, 2012
(amounts in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Interest rate derivatives not designated as accounting hedges (1)	$	(46	)	$	(46	)	$	(46	)	$	(46	)
Commodity-based derivative contracts not designated as accounting hedges (1)	$	(50	)	$	(50	)	$	(12	)	$	(12	)
DPC Credit Agreement due 2016 (2)	$	(875	)	$	(867	)	$	(880	)	$	(874	)
DMG Credit Agreement due 2016 (3)	$	(507	)	$	(510	)	$	(535	)	$	(537	)
Common stock warrants	$	(20	)	$	(20	)	$	(20	)	$	(20	)

__________________________________________


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


(2)	Carrying amount includes unamortized premiums of $40 million and $43 million at March 31, 2013 and December 31, 2012, respectively. The fair value of the DPC Credit Agreement is classified within Level 2 of the fair value hierarchy. Please read Note 19—Subsequent Events for further discussion.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012


(3)	Carrying amount includes unamortized premiums of $16 million and $18 million as of March 31, 2013 and December 31, 2012, respectively. The fair value of the DMG Credit Agreement is classified within Level 2 of the fair value hierarchy. Please read Note 19—Subsequent Events for further discussion.

Note 8—Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income, net of tax, by component for the three months ended March 31, 2013 and 2012 are as follows:



	Successor		Predecessor
	Three Months Ended March 31, 2013		Three Months Ended March 31, 2012
(amounts in millions)	Defined Benefit Pension Items		Defined Benefit Pension Items
Beginning of period	$	11	$	1
Current period other comprehensive income:
Other comprehensive income before reclassifications	—		—
Amounts reclassified from accumulated other comprehensive income	—		(1		)
Net current period other comprehensive income	$	—	$	(1	)
End of period	$	11	$	—

Note 9—Inventory

A summary of our inventories is as follows:



(amounts in millions)	March 31, 2013		December 31, 2012
Materials and supplies	$	45	$	46
Coal	37		52
Fuel oil	3		3
Emissions allowances	8		—
Total	$	93	$	101

Note 10—Variable Interest Entities

DNE. Effective October 1, 2012, the DNE Debtor Entities were deconsolidated. As of March 31, 2013 and December 31, 2012, we had less than $1 million in net receivables from the DNE Debtor Entities related to the Service Agreements included in our unaudited condensed consolidated balance sheets. We account for our investment in the DNE Debtor Entities using the cost method and have a carrying amount of zero. Our maximum exposure to loss related to our investment in the DNE Debtor Entities is limited to our net receivables as we have no obligation to provide funding to the DNE Debtor Entities on an ongoing basis. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting in our Form 10-K for further discussion. Also, please read Note 14—Related Party Transactions for a discussion of the Service Agreements.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Note 11—Intangible Assets and Liabilities

A summary of changes in our intangible assets and liabilities is as follows:



(amounts in millions)	Gas Revenue Contracts			Coal Contracts			Gas Transport			Total
December 31, 2012	$	202		$	115		$	(22	)	$	295
Amortization	(34		)	(31		)	2			(63		)
March 31, 2013 (1)	$	168		$	84		$	(20	)	$	232

__________________________________________


(1)	The total amount of $232 million consists of $223 million in short-term Intangible assets, $51 million in long-term Intangible assets, $16 million in Accrued liabilities and other current liabilities, and $26 million in Other long-term liabilities on our unaudited condensed consolidated balance sheet.

Note 12—Debt

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



	March 31, 2013				December 31, 2012
(amounts in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
DPC Credit Agreement, due 2016 (1)	$	835	$	867	$	837	$	874
DMG Credit Agreement, due 2016 (1) (2)	491		510		517		537
	1,326				1,354
Unamortized premium on debt, net	56				61
	1,382				1,415
Less: Amounts due within one year, including unamortized premium on debt, net of $16 million and $15 million, respectively	29				29
Total Long-term debt	$	1,353			$	1,386

__________________________________________


(1)	Please read Note 18—Debt—DPC and DMG Credit Agreements in our Form 10-K for further discussion.


(2)	On March 28, 2013, we repaid $25 million of the outstanding balance of the DMG Credit Agreement at par. In connection with the repayment, we recorded a gain of approximately $1 million related to the accelerated amortization of the premium on the debt which is included in Interest expense on our unaudited condensed consolidated statements of operations.

On April 23, 2013, we entered into the Credit Agreement. Please read Note 19—Subsequent Events for further discussion.

DPC Revolving Credit Agreement

DPC, as Borrower, and certain of its subsidiaries entered into a revolving credit agreement (the “DPC Revolving Credit Agreement”), dated January 16, 2013 (the “Closing Date”). Borrowings under the DPC Revolving Credit Agreement will be used for the ongoing working capital requirements and general corporate purposes of DPC and its subsidiaries.

The DPC Revolving Credit Agreement creates a 364-day senior secured revolving credit facility with commitments in principal amount of $150 million (the “DPC Revolving Credit Facility”), which was available on the closing date and which commitment amount may be adjusted pursuant to the terms thereof. Amounts borrowed under the DPC Revolving Credit Agreement that are repaid or prepaid may be re-borrowed. The DPC Revolving Credit Agreement will mature on January 15, 2014 (the “Maturity Date”) and the unpaid outstanding principal amount of each revolving loan thereunder will be repaid on or prior to the Maturity Date. DPC may reduce the aggregate commitments outstanding under the DPC Revolving Credit Facility without premium or penalty. DPC must pay a commitment fee at a rate of 0.50 percent per year on the average daily unused

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

amount of the commitment under the DPC Revolving Credit Facility. As of March 31, 2013, there have been no borrowings on the DPC Revolving Credit Agreement.

The DPC Revolving Credit Agreement bears interest, at DPC’s option, at either (a) 3.25 percent per annum plus the Adjusted LIBOR Rate, with respect to any Eurodollar Revolving Loan or (b) 2.25 percent per annum plus the Alternate Base Rate, with respect to any ABR Revolving Loan. DPC may elect from time to time to convert all or a portion of the revolving loans from an ABR Borrowing into a Eurodollar Borrowing or vice versa. The DPC Revolving Credit Agreement requires a mandatory prepayment only in the event the aggregate revolving loans exceed the aggregate revolving credit commitments.

On April 23, 2013, we entered into the Credit Agreement, at which time the DPC Revolving Credit Agreement was terminated. Please read Note 19—Subsequent Events for further discussion.

Restricted Cash

The following table depicts our restricted cash:



(amounts in millions)	March 31, 2013		December 31, 2012
DPC LC facilities (1)	$	210	$	220
DPC Collateral Posting Account (2)	67		63
DMG LC facility (3)	12		14
DMG Collateral Posting Account (2)	4		8
Corporate LC facilities (1)	27		27
Other (4)	2		3
Total restricted cash	$	322	$	335

__________________________________________


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


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


(3)	Includes cash posted to support the letter of credit reimbursement and collateral agreements under the DMG LC facility. Please read “Letter of Credit Facilities” in our Form 10-K for further discussion.


(4)	Includes cash posted to support a letter of credit and collateral for the corporate card program.

The DMG and DPC Credit Agreements were repaid in April 2013. Please read Note 19—Subsequent Events for further discussion.

Note 13—Commitments and Contingencies

Legal Proceedings

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

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

Stockholder Litigation Relating to the Blackstone and Icahn Merger Agreements. In connection with the 2010 and 2011 terminations of the merger agreement with an affiliate of The Blackstone Group L.P. (“Blackstone”) and the merger

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

agreement with an affiliate of Icahn Enterprises L.P. (“Icahn”), respectively, numerous stockholder lawsuits and one alleged 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 commenced. In July 2011, the Harris County District Court granted the motion of the plaintiff's lead class counsel for an award of attorney's fees and expenses. On April 4, 2013, the parties settled the matter for an immaterial amount.

Stockholder Litigation Relating to the 2011 Prepetition Restructuring. In connection with the prepetition restructuring and corporate reorganization of the DH Debtor Entities and their non-debtor affiliates in 2011 (the “2011 Prepetition Restructuring”), and specifically the DMG Transfer, a putative class action stockholder lawsuit captioned Charles Silsby v. Carl C. Icahn, et al., Case No. 12CIV2307 (the “Securities Litigation”), was filed in the United States District Court of the Southern District of New York. The lawsuit challenged certain disclosures made in connection with the DMG Transfer. We believe the plaintiff's complaint lacks merit and we continue to oppose the Securities Litigation vigorously. As a result of the filing of the voluntary petition for bankruptcy by Dynegy Inc., this lawsuit was stayed as against Dynegy Inc. and as a result of the confirmation of the Plan, the claims against Dynegy Inc. in the Securities Litigation are permanently enjoined.

On August 24, 2012, the lead plaintiff in the Securities Litigation filed an objection to the confirmation of the Plan asserting, among other things, that lead plaintiff should be permitted to opt-out of the non-debtor releases and injunctions (the “Non-Debtor Releases”) in the Plan on behalf of all putative class members. We opposed that relief. On October 1, 2012, the Bankruptcy Court ruled that lead plaintiff did not have standing to object to the Plan and did not have authority to opt-out of the Non-Debtor Releases on behalf of any other party-in-interest. Accordingly, the Securities Litigation may only proceed against the non-debtor defendants with respect to members of the putative class who individually opted out of the Non-Debtor Releases. The lead plaintiff filed a notice of appeal on October 10, 2012.

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 we individually, and in conjunction with other energy companies, engaged in an illegal scheme to inflate natural gas prices in four states by providing false information to natural gas index publications. In July 2011, the court granted defendants’ motions for summary judgment, thereby dismissing all of plaintiffs’ claims. Plaintiffs appealed the decision to the Ninth Circuit Court of Appeals which reversed the summary judgment on April 10, 2013. We are assessing next steps in the appellate process.

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 appealed 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. On August 20, 2012, the Dallas Court of Appeals reversed the Dallas District Court and reinstated the award. IGC and the other respondents filed a petition for review with the Texas Supreme Court on December 5, 2012. As a result of the uncertainty surrounding the outcome of PPE’s appeal, we did not assign any value to this potential receivable in fresh-start accounting.

Pacific Northwest Refund Proceedings. Dynegy Power Marketing, LLC (“DYPM”), along with numerous other companies that sold power in the Pacific Northwest in 2000-2001, are parties to a complaint filed in 2001 with FERC challenging bilateral contract pricing by claiming manipulation of the electricity market in California produced unreasonable prices in the Pacific Northwest. DYPM previously settled all California refund claims, but did not settle with certain complainants seeking refunds in the Pacific Northwest. In December 2011, DYPM received a Notice of Settlement from The City of Seattle (“Seattle”) claiming that it paid approximately $2 million to DYPM above the mitigated market clearing price set for the California market in 2000-2001. In May 2012, Seattle made an initial settlement demand of $744 thousand plus interest. DYPM and Seattle reached a settlement whereby DYPM agreed to pay Seattle $180 thousand (inclusive of all interest) to settle all claims between Seattle and DYPM in these proceedings. On November 29, 2012, FERC issued a letter order approving the settlement agreement. There is the risk for “ripple claims” from other sellers, but the efficacy of these claims is currently being litigated and any potential impact to DYPM from ripple claims is impossible to predict at this stage.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Other Commitments and Contingencies

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, plant sites, power generation assets and LPG vessel charters. The following describes the more significant commitments outstanding at March 31, 2013.

Vermilion and Baldwin Groundwater. We have implemented hydrogeologic investigations for the CCR surface impoundment at our Baldwin facility and for two CCR surface impoundments at our Vermilion facility in response to a request by the Illinois EPA. Groundwater monitoring results indicate that these CCR surface impoundments impact onsite groundwater at these sites.

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

On April 2, 2012, we submitted to the Illinois EPA proposed corrective action plans for two of the CCR surface impoundments at the Vermilion facility. The proposed corrective action plans reflect the results of a hydrogeologic investigation, which indicate that the facility’s old east and north CCR impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans include groundwater monitoring and recommend closure of both CCR impoundments, including installation of a geosynthetic cover. In addition, we submitted an application to the Illinois EPA to establish a groundwater management zone while impacts from the facility are mitigated. The preliminary estimated cost of the recommended closure alternative for both impoundments, including post-closure care, is approximately $14 million. The Vermilion facility also has a third CCR surface impoundment, the new east impoundment that is lined and is not known to impact groundwater. Although not part of the proposed corrective action plans, if we decide to close the new east impoundment by removing its CCR contents concurrent with the recommended closure alternative for the old east and north impoundments, the associated estimated closure cost would add an additional $2 million to the above estimate.

In July 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at the Baldwin and Vermilion facilities. In response, we submitted to the Illinois EPA a proposed compliance commitment agreement for each facility. For Vermilion, we proposed to implement the previously submitted corrective action plans and, for Baldwin, we proposed to perform additional studies of hydrogeologic conditions and apply for a groundwater management zone in preparation for submittal, as necessary, of a corrective action plan. In October 2012, the Illinois EPA notified us that it would not issue proposed compliance commitment agreements for Vermilion and Baldwin. In December 2012, the Illinois EPA provided written notice that it may pursue legal action with respect to each matter through referral to the Illinois Office of the Attorney General. In response to further discussions with the Illinois EPA, in March 2013 we submitted proposals to evaluate options concerning our proposed corrective action plans at Vermilion and to perform further hydrogeological study needed to analyze corrective action alternatives at Baldwin. At this time we cannot reasonably estimate the costs of resolving these matters, but resolution of these matters may cause us to incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows.

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 individual NPDES (or SPDES) permits on a case-by-case basis.

The environmental groups that participate in our NPDES permit proceedings generally argue that only closed cycle cooling meets the BTA requirement. The issuance and renewal of the NPDES permit for one of our power generation facilities (Moss Landing) was challenged on this basis. The Moss Landing NPDES permit, which was issued in 2000, does not require closed cycle cooling and was challenged by a local environmental group. In August 2011, the Supreme Court of California affirmed the appellate court’s decision upholding the permit.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Other future NPDES 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.

In September 2012, the Illinois EPA issued a renewal NPDES permit for the Havana Power Station. In October 2012, environmental interest groups filed a petition for review with the Illinois Pollution Control Board challenging the permit. The petitioners allege that the permit does not adequately address the discharge of wastewaters associated with newly installed air pollution control equipment (i.e., a spray dryer absorber and activated carbon injection system to reduce SO₂ and mercury air emissions) at Havana. We dispute the allegations and will defend the permit vigorously. The permit remains in effect during the appeal. The outcome of the appeal is uncertain at this time.

Station Power Proceedings. On May 4, 2010, the U.S. Court of Appeals for the D.C. Circuit (the “D.C. Circuit”) vacated FERC’s acceptance of station power rules for the CAISO market and remanded the case for further proceedings at FERC. On August 30, 2010, FERC issued an Order on Remand (“remand order”) effectively disclaiming jurisdiction over how the states impose retail station power charges. Due to reservation-of-rights language in the California utilities’ state-jurisdictional station power tariffs, the California utilities have argued that FERC’s ruling requires California generators to pay state-imposed retail charges back to the date of enrollment by the facilities in the CAISO’s station period program. The remand order could impact FERC’s station power policies in all of the organized markets throughout the nation. On February 28, 2011, the FERC issued an order denying rehearing of the remand order. Dynegy Moss Landing, LLC, together with other generators, filed an appeal of the remand order in the D.C. Circuit. On December 18, 2012, the D.C. Circuit issued an order denying the appeal of the generator group and affirming FERC’s orders on remand.

On November 18, 2011, PG&E filed with the CPUC, seeking authorization to begin charging generators station power charges, and to assess such charges retroactively, which the Company and other generators have challenged. Dynegy Morro Bay, LLC, Dynegy Moss Landing, LLC and Dynegy Oakland, LLC filed a protest with the CPUC objecting to PG&E’s filing. That protest is still pending. The CPUC Commissioners were scheduled to vote on a draft resolution that rejected the arguments in our protest and approved PG&E’s proposed station power charges, including retroactive implementation of such charges, on October 15, 2012. However, the draft resolution was withdrawn from the Commission’s calendar and has not yet been rescheduled for a vote. We believe we have established an appropriate accrual.

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

Indemnifications and Guarantees

In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, 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.

Indemnities

The indemnifications discussed below were settled or discharged pursuant to the Plan and the Confirmation Order with respect to Dynegy.

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. Even though Dynegy was discharged from any claims pursuant to the Plan and Confirmation Order, Dynegy Power Generation Inc., DPC, DMG and DYPM remain jointly and severally liable for any indemnification claims (the “LS Indemnity

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Entities”). 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 the LS Indemnity Entities 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, the LS Indemnity Entities may be required 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 are not required to accrue a liability for and no significant expenses have been incurred under these indemnities.

Illinois Power Company Indemnities. We have indemnified third parties against losses resulting from possible adverse regulatory actions taken by the ICC that could prevent Illinois Power Company from recovering costs incurred in connection with purchased natural gas and investments in specified items. Even though Dynegy was discharged from any claims pursuant to the Plan and Confirmation Order, Illinova Corporation (“Illinova”) remains liable for any indemnification claims. Although there is no absolute limitation on Illinova’s liability under this indemnity, the amount of the indemnity is limited to 50 percent of any such losses. We have in the past made certain payments in respect of these indemnities following regulatory action by the ICC, and have established reserves for further potential indemnity claims.

Other Indemnities. We entered into indemnifications regarding environmental, tax, employee and other representations when completing asset sales such as, but not limited, to Calcasieu and Heard County power generating facilities and the sale of our midstream business (“DMSLP”). DPC remains the sole entity liable for indemnification claims with respect to Calcasieu and Heard County. DYPM remains liable for indemnification claims with respect to DMSLP. As of March 31, 2013, no claims have been made against and we have not recorded a liability for these indemnities.

Guarantees

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 March 31, 2013, 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 $52 million under the guarantee. No amount has been accrued related to this guarantee as we consider the likelihood of a default to be remote.

Other Minimum Commitments

We are party to two charter agreements related to VLGCs previously utilized in our former global liquids business. The primary term of one charter is through September 2013 while the primary term of the second charter is through September 2014. Both of these VLGCs have been sub-chartered to a wholly-owned subsidiary of Transammonia Inc. on terms that are identical to the terms of the original charter agreements. The aggregate minimum base commitments of the charter party agreements are approximately $14 million and $11 million for the years 2013 and 2014, respectively. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreements.

Note 14—Related Party Transactions

The following tables summarize the Accounts receivable, affiliates, and Accounts payable, affiliates, on our unaudited condensed consolidated balance sheets as of March 31, 2013 and December 31, 2012; and cash received (paid) for the three months ended March 31, 2013 which is related to various agreements with Dynegy Inc., as discussed below.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012



	Successor						Predecessor
	March 31, 2013				Three Months Ended March 31, 2013		Three Months Ended March 31, 2012
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates		Cash Received		Cash Received
Service Agreements	$	1	$	1	$	1	$	11
EMA Agreements	—		—		—		1
Total	$	1	$	1	$	1	$	12



	December 31, 2012
(amounts in millions)	Accounts Receivable, Affiliates		Accounts Payable, Affiliates
Service Agreements	$	1	$	1
EMA Agreements	—		—
Total	$	1	$	1

Service Agreements. Legacy Dynegy and certain of our subsidiaries (collectively, the “Providers”) provided certain services (the “Services”) to DCIH and certain of its subsidiaries, and certain of our subsidiaries during the three months ended March 31, 2012. Additionally, we provide certain services to the DNE Debtor Entities. Service Agreements between Legacy Dynegy and the recipients govern the terms under which such Services are provided.

As a result of the Merger, transactions between DH and Legacy Dynegy executed under the Service Agreements subsequent to September 30, 2012, are no longer considered related party transactions because they eliminate in consolidation.

On October 1, 2012, Dynegy deconsolidated the DNE Debtor Entities. Please read Note 1—Organization and Operations—Chapter 11 Filing and Emergence from Bankruptcy in our Form 10-K for further discussion. Our unaudited condensed consolidated statement of operations includes $2 million of power purchased from our unconsolidated affiliate, which is reflected in Revenues for the three months ended March 31, 2013.

Energy Management Agreements. Certain of our subsidiaries have entered into an Energy Management Agency Services Agreement (an “EMA”) with DMG. Pursuant to the EMA, our subsidiaries will provide power management services to other subsidiaries, consisting of marketing power and capacity, capturing pricing arbitrage, scheduling dispatch of power, communicating with the applicable ISOs or RTOs, purchasing replacement power, and reconciling and settling ISO or RTO invoices. In addition, certain of our subsidiaries will provide fuel management services, consisting of procuring the requisite quantities of fuel and emissions credits, assisting with transportation, scheduling delivery of fuel, assisting with development and implementation of fuel procurement strategies, marketing and selling excess fuel and assisting with the evaluation of present and long-term fuel purchase and transportation options. Our subsidiaries will also assist other subsidiaries with risk management by entering into one or more risk management transactions, the purpose of which is to set the price or value of any commodity or to mitigate or offset any change in the price or value of any commodity. Our subsidiaries may from time to time provide other services as the parties may agree. Our unaudited condensed consolidated statement of operations includes $136 million of power purchased from affiliates, which is reflected in Revenues, and $55 million of coal sold to affiliates, which is reflected in Costs of sales, for the three months ended March 31, 2012. This affiliate activity is presented net of third party activity within Revenue and Cost of sales. Also, please read Note 6—Risk Management Activities, Derivatives and Financial Instruments for derivative balances with affiliates. As a result of the DMG Acquisition, transactions executed under the Energy Management Agreement are not considered related party transactions subsequent to June 5, 2012 because they eliminate in consolidation.

DMG Transfer and Undertaking Agreement. During the three months ended March 31, 2012, we recognized $24 million in interest income related to the Undertaking Agreement which is included in Other income and expense, net, in our unaudited condensed consolidated statement of operations. In addition, we did not receive any payments from Legacy Dynegy during the three months ended March 31, 2012 related to the Undertaking Agreement. The Undertaking Agreement was terminated on June 5, 2012 in connection with the execution of the Settlement Agreement.

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

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

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

Note 15—Income Taxes

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



	Successor			Predecessor
(amounts in millions, except rates)	Three Months Ended March 31, 2013			Three Months Ended March 31, 2012
Income tax benefit	$	—		$	6

Effective tax rate	—		%	1		%

For the three months ended March 31, 2013, the difference between the effective rate of zero percent and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. As of March 31, 2013, we do not believe we will produce sufficient future taxable income, nor are there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences.

For the three months ended March 31, 2012, the difference between the effective rates of 1 percent and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. As of March 31, 2012, we did not believe we would produce sufficient future taxable income, nor were there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences.

Note 16—Pension and Other Post-Employment Benefit Plans

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

As a result of the DMG Transfer on September 1, 2011, we and our subsidiaries were no longer the primary participant in certain defined benefit pension and other post-employment benefit plans sponsored by Legacy Dynegy; therefore, we began accounting for our participation in these plans as multi-employer plans. The transfer of the plans was recorded as part of the DMG Transfer as a common control transaction.

Additionally, we completed the DMG Acquisition on June 5, 2012, and we were once again the primary participant in certain defined benefit pension and other post-employment benefit plans. As a result of the Merger on September 30, 2012, we became the sponsor of these plans.

Components of Net Periodic Benefit Cost. The components of net periodic benefit cost for the three months ended March 31, 2013 were:



	Three Months Ended March 31, 2013
(amounts in millions)	Pension Benefits			Other Benefits
Service cost benefits earned during period	$	2		$	—
Interest cost on projected benefit obligation	3			1
Expected return on plan assets	(4		)	—
Total net periodic benefit cost	$	1		$	1

There were no such net periodic benefit costs related to the Predecessor for the three months ended March 31, 2012, as the costs related to these plans were included in Legacy Dynegy.

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Contributions. During the three months ended March 31, 2013, we made $2 million in voluntary contributions to our pension plans and none to our other post-retirement benefit plans. We are not required to make contributions to our pension plans and other postretirement benefit plans during 2013; however, we may elect to make voluntary contributions.

Note 17—Loss Per Share

The reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations of our common stock outstanding during the period is shown in the following table. Basic loss per share represents the amount of losses for the period available to each share of our common stock outstanding during the period. Diluted loss per share represents the amount of losses for the period available to each share of our common stock outstanding during the period plus each share that would have been outstanding assuming the issuance of common shares for all dilutive potential common shares outstanding during the period. Please read Note 23—Capital Stock in our Form 10-K for further discussion.

Prior to the Merger, DH was organized as a limited liability company and the capital structure of DH did not change until September 30, 2012. Although Legacy Dynegy’s shares were publicly traded, DH did not have any publicly traded shares during the Predecessor periods; therefore, no loss per share is presented for the period ended March 31, 2012.



(in millions, except per share amounts)	Three Months Ended March 31, 2013
Loss from continuing operations for basic and diluted loss per share	$	(142	)

Basic weighted-average shares	100
Effect of dilutive securities—stock options and restricted stock	—
Diluted weighted-average shares	100

Loss per share from continuing operations:
Basic	$	(1.42	)
Diluted (1)	$	(1.42	)

__________________________________________


(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 the period ended March 31, 2013.

Note 18—Segment Information

We report the results of our operations in two segments: (i) Coal and (ii) Gas. In connection with our emergence from bankruptcy, we deconsolidated the DNE Debtor Entities and we began accounting for our investment in the DNE Debtor Entities using the cost method. Accordingly, we have reclassified DNE's operating results as discontinued operations in the consolidated financial statements for all periods presented. Subsequent to our emergence from bankruptcy, management does not consider general and administrative expense when evaluating the performance of our Coal and Gas segments, but instead evaluates general and administrative expense on an enterprise wide basis. Accordingly, we have recast our segments to present general and administrative expense in Other and Eliminations for all periods presented.

On September 1, 2011, we completed the DMG Transfer; therefore, the results of our Coal segment are not included for the three months ended March 31, 2012. Additionally, on June 5, 2012, we reacquired the Coal segment through the DMG Acquisition; therefore, the results of our Coal segment are included for the three months ended March 31, 2013. Please read Note 3—Acquisitions—DMG Acquisition for further discussion.

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2013 and 2012 is presented below:

DYNEGY INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2013 and 2012

Segment Data as of and for the Three Months Ended March 31, 2013

(amounts in millions)



	Successor
	Coal			Gas			Other and Eliminations			Total
Unaffiliated revenues:
Domestic	$	87		$	231		$	—		$	318
Total revenues	$	87		$	231		$	—		$	318

Depreciation and amortization	$	(13	)	$	(40	)	$	(1	)	$	(54	)
General and administrative expense	—			—			(22		)	(22		)

Operating loss	$	(80	)	$	(8	)	$	(27	)	$	(115	)

Bankruptcy reorganization items, net	—			—			(1		)	(1		)
Interest expense										(28		)
Other items, net	—			1			1			2
Loss before income taxes										(142		)
Income tax benefit										—
Net loss										$	(142	)

Identifiable assets (domestic)	$	1,234		$	2,716