Edgar Filing: DYNEGY INC.

DYN-2014.3.31-10Q

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, 2014

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 ý		Accelerated filer o
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

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 ¨

Table of Contents

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, 100,343,834 shares outstanding as of May 2, 2014.

Table of Contents

TABLE OF CONTENTS



		Page
DEFINITIONS		i

PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS:	1

Consolidated Balance Sheets:
As of March 31, 2014 and December 31, 2013		1
Consolidated Statements of Operations:
For the three months ended March 31, 2014 and 2013		3
Consolidated Statements of Comprehensive Income (Loss):
For the three months ended March 31, 2014 and 2013		4
Consolidated Statements of Cash Flows:
For the three months ended March 31, 2014 and 2013		5
Notes to Consolidated Financial Statements		6

Item 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	29
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	47
Item 4.	CONTROLS AND PROCEDURES	48

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS	49
Item 1A.	RISK FACTORS	49
Item 6.	EXHIBITS	49

Signature		50

Table of Contents

DEFINITIONS

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



AEGC or Genco		Ameren Energy Generating Company
AEM		Ameren Energy Marketing Company
AER		New Ameren Energy Resources, LLC
AERG		New AERG, LLC
Ameren		Ameren Corporation
ARO		Asset Retirement Obligation
ASU		Accounting Standards Update
CAA		Clean Air Act
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
CSAPR		Cross-State Air Pollution Rule
CWA		Clean Water Act
DH		Dynegy Holdings, LLC (formerly known as Dynegy Holdings Inc.)
DMG		Dynegy Midwest Generation, LLC
DPC		Dynegy Power, LLC
EBITDA		Earnings Before Interest, Taxes, Depreciation and Amortization
EEI		Electric Energy, Inc.
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
GW		Gigawatts
IBEW		International Brotherhood of Electrical Workers
IMA		In-market Asset Availability
IPCB		Illinois Pollution Control Board
IPGC or Genco		Illinois Power Generating Company (formerly known as Ameren Energy Generating Company)
IPH		Illinois Power Holdings, LLC
IPM		Illinois Power Marketing Company (formerly known as Ameren Energy Marketing Company)
IPR		Illinois Power Resources, LLC (formerly known as New Ameren Energy Resources, LLC)
IPRG		Illinois Power Resources Generating, LLC (formerly known as New AERG, LLC)
ISO		Independent System Operator
ISO-NE		Independent System Operator New England
kW		Kilowatt
LC		Letter of Credit
LGE		Louisville Gas and Electric Company
LIBOR		London Interbank Offered Rate
LMP		Locational Marginal Pricing
LOLE		Loss of Load Expectation

Table of Contents



LPG		Liquefied Petroleum Gas
LRZ		Local Resource Zones
LSE		Load Serving Entity
LTPP		Long-Term Procurement Plan
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		One Million British Thermal Units
Moody’s		Moody’s Investors Service Inc.
MW		Megawatts
MWh		Megawatt Hour
NAAQS		National Ambient Air Quality Standards
NM		Not Meaningful
NOL		Net operating loss
NSPS		New Source Performance Standards
NSR		New Source Review
NYISO		New York Independent System Operator
OCI		Other Comprehensive Income
PG&E		Pacific Gas and Electric Company
PJM		PJM Interconnection, LLC
PRIDE		Producing Results through Innovation by Dynegy Employees
PSD		Prevention of Significant Deterioration
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
RPM		Reliability Pricing Model
RTO		Regional Transmission Organization
SACCWIS		Statewide Advisory Committee on Cooling Water Intake Structures
S&P		Standard & Poor’s Ratings Services
SCE		Southern California Edison
SEC		U.S. Securities and Exchange Commission
SO2		Sulfur Dioxide
SPDES		State Pollutant Discharge Elimination System
TVA		Tennessee Valley Authority
VaR		Value at Risk

PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



	March 31, 2014			December 31, 2013
ASSETS
Current Assets
Cash and cash equivalents	$	996		$	843
Accounts receivable, net of allowance for doubtful accounts of $1 and zero, respectively	409			420
Inventory	181			181
Assets from risk management activities	18			25
Intangible assets	86			108
Prepayments and other current assets	147			108
Total Current Assets	1,837			1,685
Property, Plant and Equipment	3,532			3,527
Accumulated depreciation	(270		)	(212		)
Property, Plant and Equipment, Net	3,262			3,315
Other Assets
Assets from risk management activities	4			11
Intangible assets	61			68
Deferred income taxes	79			100
Other long-term assets	109			112
Total Assets	$	5,352		$	5,291

See the notes to consolidated financial statements.

Table of Contents

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)



	March 31, 2014			December 31, 2013
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Accounts payable	$	370		$	329
Accrued interest	35			13
Deferred income taxes	79			100
Intangible liabilities	60			62
Accrued liabilities and other current liabilities	138			139
Liabilities from risk management activities	109			65
Debt, current portion	36			13
Total Current Liabilities	827			721
Debt, long-term portion	1,970			1,979
Other Liabilities
Liabilities from risk management activities	28			33
Asset retirement obligations	179			173
Other long-term liabilities	178			178
Total Liabilities	3,182			3,084
Commitments and Contingencies (Note 10)

Stockholders’ Equity
Common Stock, $0.01 par value, 420,000,000 shares authorized at March 31, 2014 and December 31, 2013; 100,313,945 shares and 100,202,036 shares issued and outstanding at March 31, 2014 and December 31, 2013, respectively	1			1
Additional paid-in capital	2,618			2,614
Accumulated other comprehensive income, net of tax	55			58
Accumulated deficit	(504		)	(463		)
Total Dynegy Stockholders’ Equity	2,170			2,210
Noncontrolling interest	—			(3		)
Total Equity	2,170			2,207
Total Liabilities and Equity	$	5,352		$	5,291

See the notes to consolidated financial statements.

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

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



	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
Revenues	$	762		$	318
Cost of sales, excluding depreciation expense	(552		)	(284		)
Gross margin	210			34
Operating and maintenance expense	(110		)	(71		)
Depreciation expense	(67		)	(54		)
Gain on sale of assets	—			1
General and administrative expense	(26		)	(22		)
Acquisition and integration costs	(6		)	(3		)
Operating income (loss)	1			(115		)
Interest expense	(30		)	(28		)
Other income and expense, net	(6		)	1
Loss before income taxes	(35		)	(142		)
Income tax expense	(2		)	—
Net loss	(37		)	(142		)
Less: Net income attributable to noncontrolling interests	4			—
Net loss attributable to Dynegy Inc.	$	(41	)	$	(142	)

Loss Per Share (Note 14):
Basic loss per share attributable to Dynegy Inc.	$	(0.41	)	$	(1.42	)
Diluted loss per share attributable to Dynegy Inc.	$	(0.41	)	$	(1.42	)

Basic shares outstanding	100			100
Diluted shares outstanding	101			100

See the notes to consolidated financial statements.

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(unaudited) (in millions)



	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
Net loss	$	(37	)	$	(142	)
Other comprehensive loss before reclassifications:
Actuarial loss (net of tax of zero and zero, respectively)	(3		)	—
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service cost and actuarial loss, net of tax of zero and zero, respectively)	(1		)	—
Other comprehensive loss, net of tax	(4		)	—
Comprehensive loss	(41		)	(142		)
Less: Comprehensive income attributable to noncontrolling interests	3			—
Total comprehensive loss attributable to Dynegy Inc.	$	(44	)	$	(142	)

See the notes to consolidated financial statements.

Table of Contents

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)



	Three Months Ended March 31, 2014			Three Months Ended March 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	$	(37	)	$	(142	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation expense	67			54
Non-cash interest expense (benefit)	5			(4		)
Amortization of intangibles	16			63
Risk-management activities	52			38
Gain on sale of assets	—			(1		)
Deferred income taxes	2			—
Change in value of common stock warrants	6			—
Other	9			5
Changes in working capital:
Accounts receivable, net	23			22
Inventory	—			8
Prepayments and other current assets	(31		)	(18		)
Accounts payable and accrued liabilities	55			(26		)
Affiliate transactions	—			(1		)
Changes in non-current assets	(2		)	(4		)
Changes in non-current liabilities	1			(1		)
Net cash provided by (used in) operating activities	166			(7		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(17		)	(20		)
Decrease in restricted cash	—			13
Other investing	—			1
Net cash used in investing activities	(17		)	(6		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs	11			(3		)
Repayments of borrowings, including debt extinguishment costs	(2		)	(28		)
Interest rate swap settlement payments	(4		)	—
Other financing	(1		)	—
Net cash provided by (used in) financing activities	4			(31		)
Net increase (decrease) in cash and cash equivalents	153			(44		)
Cash and cash equivalents, beginning of period	843			348
Cash and cash equivalents, end of period	$	996		$	304

See the notes to consolidated financial statements.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Note 1—Basis of Presentation and Organization

The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements but does not include all disclosures required by GAAP. The unaudited 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, 2013, filed with the SEC on February 27, 2014, which we refer to as our “Form 10-K.” 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.

Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three segments in our unaudited consolidated financial statements: (i) the Coal segment (“Coal”), (ii) the IPH segment (“IPH”) and (iii) the Gas segment (“Gas”). Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). Please read Note 16—Segment Information for further discussion. All significant intercompany transactions have been eliminated.

Illinois Power Holdings, LLC (“IPH”) and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“IPGC” or “Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.

Note 2—Accounting Policies

The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements in our Form 10-K. There have been no significant changes to these policies during the three months ended March 31, 2014.

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 Standards Adopted During the Current Period

Presentation of Unrecognized Tax Benefits. In July 2013, the FASB issued ASU 2013-11-Income Taxes (Topic 740): Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists. The provisions of the rule require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for an NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability and should not be combined with deferred tax assets. The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2013, with early adoption permitted. The adoption of this ASU did not have an impact on our balance sheets, statements of income, statements of cash flow or disclosures.

Joint and Several Liability Arrangements. In February 2013, the FASB issued ASU 2013-04-Liabilities (Topic 405): Obligations Resulting from Joint and Several Liability Arrangements for Which the Total Amount of the Obligation Is Fixed at the Reporting Date. The provisions of the rule require an entity to measure obligations resulting from joint and several liability

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

arrangements for which the total amount of the obligation within the scope of this guidance is fixed at the reporting date, as the sum of (i) the amount the reporting entity agreed to pay on the basis of its arrangement among its co-obligors and (ii) any additional amount the reporting entity expects to pay on behalf of its co-obligors. The guidance in this update also requires an entity to disclose the nature and amount of the obligation as well as other information about those obligations. ASU 2013-04 is effective for fiscal years, and interim periods within those years, beginning after December 15, 2013. The adoption of this ASU did not have an impact on our balance sheets, statements of income, statements of cash flow or disclosures.

Accounting Standards Not Yet Adopted

Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this Update change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this update are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We do not anticipate the adoption of this ASU having an impact on our balance sheets, statements of income, statements of cash flow or disclosures.

Note 3—Acquisition

AER Transaction Agreement

On December 2, 2013, pursuant to the terms of the definitive agreement dated as of March 14, 2013 and as amended on December 2, 2013 (the “AER Transaction Agreement”) by and between Illinois Power Holdings, LLC (“IPH”), an indirect wholly-owned subsidiary of Dynegy, and Ameren Corporation (“Ameren”), IPH completed its acquisition from Ameren of 100 percent of the equity interests of New Ameren Energy Resources, LLC (“AER”) and its subsidiaries (the “AER Acquisition”). The acquisition added 4,062 MW of generation in Illinois and also included the Homefield Energy retail business. There was no cash consideration or stock issued as part of the purchase price. We acquired AER and its subsidiaries through IPH which maintains corporate separateness from our legal entities outside of IPH.

In connection with the AER Acquisition, Ameren retained certain historical obligations of Illinois Power Resources, LLC (“IPR”) and its subsidiaries, including certain historical environmental and tax liabilities. Approximately $825 million in aggregate principal amount of Genco notes remained outstanding as an obligation of Genco. Additionally, Ameren is required to maintain its existing credit support, including all of its collateral obligations with respect to Illinois Power Marketing Company (“IPM”), for a period not to exceed two years following closing. Dynegy has provided a limited guaranty of certain obligations of IPH up to $25 million (the “Limited Guaranty”) as further described in Note 10—Commitments and Contingencies—Guarantees.

We incurred costs of $6 million and $3 million included in Acquisition and integration costs in our unaudited consolidated statements of operations for the three months ended March 31, 2014 and 2013, respectively. Revenues of $204 million and net loss of $58 million attributable to IPH are included in our unaudited consolidated statements of operations for the three months ended March 31, 2014.

Pro Forma Results. The unaudited pro forma financial results for the three months ended March 31, 2013 assume the AER Acquisition had occurred on January 1, 2013. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed as of January 1, 2013, nor are they indicative of future results of operations.



(amounts in millions)	Three Months Ended March 31, 2013
Revenues	$	595
Net loss	$	(153	)
Net loss attributable to noncontrolling interests	$	(1	)
Net loss attributable to Dynegy Inc.	$	(152	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Note 4—Risk Management Activities, Derivatives and Financial Instruments

The nature of our business necessarily involves market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially settled and other types of contracts consistent with our commodity risk management policy. Our 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 three-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 consolidated statements of operations. We 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 consolidated statements of operations until the delivery occurs.

Quantitative Disclosures Related to Financial Instruments and Derivatives

As of March 31, 2014, we had net purchases and sales of derivative contracts outstanding in the following quantities:



Contract Type	Hedge Designation	Quantity		Unit of Measure	Fair Value (1)
(dollars and quantities in millions)		Purchases (Sales)			Asset (Liability)
Commodity contracts:
Electricity derivatives (2)	Not designated	(22	)	MWh	$	(78	)
Natural gas derivatives (2)	Not designated	110		MMBtu	$	5
Diesel fuel	Not designated	13		Gallons	$	—
Coal derivatives	Not designated	1		Metric Ton	$	(3	)
Heat rate derivatives	Not designated	—		MWh/MMBtu	$	(1	)
Emissions derivatives	Not designated	3		Metric Ton	$	(1	)
Interest rate swaps	Not designated	796		Dollars	$	(40	)
Common stock warrants	Not designated	16		Warrant	$	(27	)

__________________________________________


(1)	Includes both asset and liability risk management positions, but excludes margin and collateral netting, as discussed below.


(2)	Mainly comprised of swaps, options and physical forwards. Electricity derivatives also include FTRs.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Derivatives on the Balance Sheet. The following tables present the fair value and balance sheet classification of derivatives in the unaudited consolidated balance sheets as of March 31, 2014 and the consolidated balance sheets as of December 31, 2013 segregated by type of contract segregated by assets and liabilities. As of March 31, 2014 and December 31, 2013, there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets.



			March 31, 2014
						Gross amounts offset in the balance sheet
Contract Type		Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
	Commodity contracts	Assets from risk management activities	$	127		$	(105	)	$	—	$	22
	Total derivative assets		$	127		$	(105	)	$	—	$	22

Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(205	)	$	105		$	3	$	(97	)
	Interest rate contracts	Liabilities from risk management activities	(40		)	—			—		(40		)
	Common stock warrants	Other long-term liabilities	(27		)	—			—		(27		)
	Total derivative liabilities		$	(272	)	$	105		$	3	$	(164	)
Total derivatives			$	(145	)	$	—		$	3	$	(142	)



			December 31, 2013
						Gross amounts offset in the balance sheet
Contract Type		Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
	Commodity contracts	Assets from risk management activities	$	103		$	(67	)	$	—	$	36
	Total derivative assets		$	103		$	(67	)	$	—	$	36

Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(122	)	$	67		$	4	$	(51	)
	Interest rate contracts	Liabilities from risk management activities	(47		)	—			—		(47		)
	Common stock warrants	Other long-term liabilities	(21		)	—			—		(21		)
	Total derivative liabilities		$	(190	)	$	67		$	4	$	(119	)
Total derivatives			$	(87	)	$	—		$	4	$	(83	)

The following table summarizes our cash collateral posted as of March 31, 2014 and December 31, 2013, 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, 2014				December 31, 2013
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)
Prepayments and other current assets	$	76	$	3	$	47	$	4

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Impact of Derivatives on the Consolidated Statements of Operations

The following discussion and tables present the location and amount of gains and losses on derivative instruments in our unaudited consolidated statements of operations.

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).

The impact of mark-to-market gains (losses) on our unaudited consolidated statements of operations for the three months ended March 31, 2014 and 2013 is presented below.



Derivatives Not Designated as Hedges	Location of Mark-to-market Gain (Loss) in Income on Derivatives	Three Months Ended March 31,
Derivatives Not Designated as Hedges		2014			2013
(amounts in millions)
Commodity contracts	Revenues	$	(60	)	$	(38	)
Interest rate contracts	Interest expense	$	7		$	—
Common stock warrants	Other income (expense), net	$	(6	)	$	—

The recognized impact of derivative financial instruments on our unaudited consolidated statements of operations for the three months ended March 31, 2014 and 2013 is presented below.



Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended March 31,
Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	2014			2013
(amounts in millions)
Commodity contracts	Revenues	$	(173	)	$	(34	)
Commodity contracts, affiliates	Revenues	$	—		$	(2	)
Interest rate contracts	Interest expense	$	3		$	—
Common stock warrants	Other income (expense), net	$	(6	)	$	—

Note 5—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.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

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, 2014 and December 31, 2013 and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid.



	Fair Value as of March 31, 2014
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	46		$	58		$	104
Natural gas derivatives	—			23			—			23
Total assets from commodity risk management activities	$	—		$	69		$	58		$	127
Liabilities:										.
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(114	)	$	(68	)	$	(182	)
Natural gas derivatives	—			(18		)	—			(18		)
Heat rate derivatives	—			—			(1		)	(1		)
Emissions derivatives	—			(1		)	—			(1		)
Coal derivatives	—			(3		)	—			(3		)
Total liabilities from commodity risk management activities	—			(136		)	(69		)	(205		)
Liabilities from interest rate contracts	—			(40		)	—			(40		)
Liabilities from outstanding common stock warrants	(27		)	—			—			(27		)
Total liabilities	$	(27	)	$	(176	)	$	(69	)	$	(272	)



	Fair Value as of December 31, 2013
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	44		$	50		$	94
Natural gas derivatives	—			9			—			9
Total assets from commodity risk management activities	$	—		$	53		$	50		$	103
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(55	)	$	(39	)	$	(94	)
Natural gas derivatives	—			(21		)	—			(21		)
Heat rate derivatives	—			—			(1		)	(1		)
Emissions derivatives	—			(2		)	—			(2		)
Coal derivatives	—			(4		)	—			(4		)
Total liabilities from commodity risk management activities	—			(82		)	(40		)	(122		)
Liabilities from interest rate contracts	—			(47		)	—			(47		)
Liabilities from outstanding common stock warrants	(21		)	—			—			(21		)
Total liabilities	$	(21	)	$	(129	)	$	(40	)	$	(190	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Level 3 Valuation Methods. The electricity derivatives classified within Level 3 are primarily financial swaps executed in illiquid trading locations, capacity contracts, off-peak power options, 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. Off-peak power options are valued using a Black-Scholes model which uses forward prices and market implied volatility. The forward market price of FTRs is derived using historical congestion patterns within the marketplace and 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, forward congestion power price spreads and illiquid power location pricing basis to liquid locations. These estimates 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. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of March 31, 2014 are as follows:



Transaction Type	Quantity		Unit of Measure	Net Fair Value			Valuation Technique	Significant Unobservable Inputs	Significant Unobservable Inputs Range
(dollars in millions)
Electricity derivatives:
Forward contracts—power (1)	(8	)	Million MWh	$	(17	)	Basis spread + liquid location	Basis spread	$7.00-$9.00
FTRs	5		Million MWh	$	7		Historical congestion	Forward price	$0.00-$10.00
Diesel fuel	4		Million Gallons	$	—		Forward prices	Forward price	$2.65-$2.80
Heat rate derivatives	180		Thousand Tons	$	(1	)	Option models	Coal/power price correlation	0%-17%
Heat rate derivatives	(316	)	Thousand MWh	$	—		Option models	Power price volatility	24%-44%

__________________________________________


(1)	Represents forward financial and physical transactions at illiquid pricing locations.

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



	Three Months Ended March 31, 2014
(amounts in millions)	Electricity Derivatives			Heat Rate Derivatives			Total
Balance at December 31, 2013	$	11		$	(1	)	$	10
Total losses included in earnings	(23		)	—			(23		)
Settlements (1)	2			—			2
Balance at March 31, 2014	$	(10	)	$	(1	)	$	(11	)
Mark-to-market losses relating to instruments held as of March 31, 2014	$	(23	)	$	—		$	(23	)



	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
Mark-to-market gains relating to instruments held as of March 31, 2013	$	—		$	1	$	1

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

__________________________________________


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

Gains and losses recognized for Level 3 recurring items are included in Revenues on the unaudited consolidated statements of operations for commodity derivatives. 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, 2014 and 2013.

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, 2014 and 2013.

Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments recognized on our balance sheet. 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, 2014 and December 31, 2013, respectively.



	March 31, 2014						December 31, 2013
(amounts in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
Tranche B-2 Term Loan, due 2020 (1)(2)	$	(790	)	$	(797	)	$	(792	)	$	(802	)
5.875% Senior Notes, due 2023 (2)	$	(500	)	$	(490	)	$	(500	)	$	(468	)
Emissions Repurchase Agreements (2)	$	(29	)	$	(36	)	$	(17	)	$	(17	)
Interest rate derivatives not designated as accounting hedges (2)	$	(40	)	$	(40	)	$	(47	)	$	(47	)
Commodity-based derivative contracts not designated as accounting hedges (3)	$	(78	)	$	(78	)	$	(19	)	$	(19	)
Common stock warrants (4)	$	(27	)	$	(27	)	$	(21	)	$	(21	)
Genco:
7.95% Senior Notes Series F, due 2032 (2)(5)	$	(223	)	$	(223	)	$	(224	)	$	(216	)
7.00% Senior Notes Series H, due 2018 (2)(5)	$	(262	)	$	(264	)	$	(259	)	$	(252	)
6.30% Senior Notes Series I, due 2020 (2)(5)	$	(202	)	$	(208	)	$	(200	)	$	(196	)

__________________________________________


(1)	Carrying amount includes an unamortized discount of $4 million as of March 31, 2014 and December 31, 2013. Please read Note 9—Debt for further discussion.


(2)	The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels.


(3)	Carrying amount of commodity-based derivative contracts excludes $3 million and $4 million of cash posted as collateral, as of March 31, 2014 and December 31, 2013, respectively.


(4)	The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels.


(5)	Combined carrying amounts as of March 31, 2014 and December 31, 2013 include unamortized discounts of $138 million and $142 million, respectively. Please read Note 9—Debt for further discussion.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Note 6—Accumulated Other Comprehensive Income (Loss)

Changes in accumulated other comprehensive income (loss), net of tax, by component, associated with our defined benefit pension and other post-employment benefit plans are as follows:



	Three Months Ended March 31,
(amounts in millions)	2014			2013
Beginning of period	$	58		$	11
Current period other comprehensive loss:
Actuarial loss (net of tax of zero and zero, respectively)	(2		)	—
Other comprehensive loss before reclassifications	(2		)	—
Amortization of unrecognized prior service cost and actuarial loss (net of tax of zero and zero, respectively) (1)	(1		)	—
Amounts reclassified from accumulated other comprehensive income	(1		)	—
Net current period other comprehensive loss	(3		)	—
End of period	$	55		$	11

__________________________________________


(1)	Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read Note 13—Pension and Other Post-Employment Benefit Plans for further discussion.

Note 7—Inventory

A summary of our inventories is as follows:



(amounts in millions)	March 31, 2014		December 31, 2013
Materials and supplies	$	80	$	81
Coal	94		92
Fuel oil	5		4
Emissions allowances (1)	2		4
Total	$	181	$	181

__________________________________________


(1)	This inventory is held as collateral by one of our counterparties as part of a financing arrangement. Please read Note 9—Debt for further discussion related to the Emissions Repurchase Agreements.

Note 8—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities:



	March 31, 2014						December 31, 2013
(amounts in millions)	Gross Carrying Amount			Accumulated Amortization			Gross Carrying Amount			Accumulated Amortization
Electricity Contracts, net	$	330		$	(199	)	$	330		$	(170	)
Coal Contracts, net	39			(139		)	39			(150		)
Gas Transport Contracts	(24		)	11			(24		)	9
Total	$	345		$	(327	)	$	345		$	(311	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

The following table presents our amortization of intangible assets and liabilities:



	Three Months Ended March 31,
(amounts in millions)	2014			2013
Electricity Contracts, net (1)	$	29		$	34
Coal Contracts, net (2)	(11		)	31
Gas Transport Contracts (2)	(2		)	(2		)
Total	$	16		$	63

__________________________________________


(1)	The amortization expense of these contracts is recognized in Revenues in our unaudited consolidated statements of operations.


(2)	The amortization expense of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Note 9—Debt

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



(amounts in millions)	March 31, 2014			December 31, 2013
Dynegy Inc.:
Tranche B-2 Term Loan, due 2020 (1)	$	794		$	796
5.875% Senior Notes, due 2023 (1)	500			500
Emissions Repurchase Agreements (1)	29			17
Genco:
7.95% Senior Notes Series F, due 2032 (1)	275			275
7.00% Senior Notes Series H, due 2018 (1)	300			300
6.30% Senior Notes Series I, due 2020 (1)	250			250
	2,148			2,138
Unamortized discount on debt, net	(142		)	(146		)
	2,006			1,992
Less: Current maturities, including unamortized discounts, net	36			13
Total Long-term debt	$	1,970		$	1,979

__________________________________________


(1)	Please read Note 12—Debt in our Form 10-K for further discussion.

The Company has a $1.275 billion credit agreement that consists of (i) an $800 million seven-year senior secured term loan B facility (the “Tranche B-2 Term Loan”) and (ii) a $475 million five-year senior secured revolving credit facility (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). Dynegy and its Subsidiary Guarantors also entered into an indenture pursuant to which Dynegy issued $500 million in aggregate principal amount of unsecured senior notes (the “Senior Notes”) at par.

At March 31, 2014 and December 31, 2013, there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit of approximately $166 million, which reduces the amount available under the Revolving Facility.

The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Based on the calculation outlined in the Credit Agreement, we are in compliance at March 31, 2014.

Senior Notes Registration Rights Agreement

In connection with the issuance and sale of the Senior Notes, Dynegy and the Subsidiary Guarantors entered into a registration rights agreement (the “Senior Notes Registration Rights Agreement”). Pursuant to the Senior Notes Registration

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Rights Agreement, Dynegy and the Subsidiary Guarantors agreed for the benefit of the holders of the Senior Notes to use commercially reasonable efforts to register with the SEC a new issue of senior notes due 2023 having substantially identical terms as the Senior Notes as part of an offer to exchange freely tradable exchange notes for the Senior Notes. In satisfaction of our obligations under the Senior Notes Registration Rights Agreement, on April 14, 2014 we completed an exchange offer of $500 million aggregate principal amount of our 5.875 percent senior notes due 2023 registered under the Securities Act of 1933 (the “Exchange Notes”) for all the Senior Notes previously issued and outstanding. The terms of the Exchange Notes are identical in all material respects to the terms of the Senior Notes, except that the Exchange Notes have been registered under the Securities Act of 1933. We did not receive any proceeds in connection with the exchange offer.

For supplemental financial information related to the Subsidiary Guarantors, please read Note 15—Condensed Consolidating Financial Information.

Genco Senior Notes

On December 2, 2013, in connection with the AER Acquisition, Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) remained outstanding as an obligation of Genco, a subsidiary of IPH. The Genco Senior Notes bear interest at rates from 6.30 percent per annum to 7.95 percent per annum and mature between 2018 and 2032.

Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness.

The following table summarizes these required ratios:



		Required Ratio
Restricted payment interest coverage ratio (1)		≥1.75
Additional indebtedness interest coverage ratio (2)		≥2.50
Additional indebtedness debt-to-capital ratio (2)		≤60%

__________________________________________


(1)	As of the date of a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.


(2)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Genco’s debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness.

Based on March 31, 2014 results, Genco’s interest coverage ratios are less than the minimum ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources. Based on our projections, we expect that Genco’s interest coverage ratios will be less than the minimum ratios required for Genco to pay dividends and incur additional third-party indebtedness until at least 2016.

Illinois Power Marketing

On January 29, 2014, IPM entered into a fully cash collateralized Letter of Credit and Reimbursement Agreement with Union Bank, N.A., pursuant to which Union Bank agreed to issue from time to time, one or more standby letters of credit in an aggregate stated amount not to exceed $25 million at any one time to support performance obligations and other general corporate activities of IPM, provided that IPM deposits in an account controlled by Union Bank an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon. Currently, IPM has deposited $10.5 million with Union Bank and issued $10 million in Letters of Credit.

Emissions Repurchase Agreements

During the fourth quarter 2013, we entered into two repurchase transactions with a third party in which we sold $6 million in California Carbon Allowances (“CCA”) credits and $11 million of Regional Greenhouse Gas Initiative (“RGGI”) inventory and received cash. In the first quarter 2014, we entered into an additional repurchase agreement with a third party in which we sold

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

$12 million RGGI inventory and received cash. We are obligated to repurchase the CCA credits in October 2014 and RGGI inventory in February 2015 at a specified price that includes a carry cost of approximately 350 basis points.

Note 10—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 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 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 U.S. District Court for the Southern District of New York. The lawsuit challenged certain disclosures made in connection with the DMG Transfer. 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 Joint Chapter 11 Plan (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. On June 4, 2013, the District Court dismissed the appeal. On July 3, 2013, the lead plaintiff filed a notice of appeal with the U.S. Court of Appeals for the Second Circuit and filed a brief on November 4, 2013. On July 19, 2013, the defendants filed a substantive motion to dismiss the plaintiff's remaining claims. On April 30, 2014, the District Court granted the defendants’ motion and dismissed the action.

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 time frame. 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 U.S. Court of Appeals for the Ninth Circuit which reversed the summary judgment on April 10, 2013. On August 26, 2013, we and the other defendants filed a request for review with the U.S. Supreme Court. On December 2, 2013, the U.S. Supreme Court issued an Order calling for the views of the U.S. Solicitor General in the matter.

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

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

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. The Texas Supreme Court held oral arguments in the matter on January 7, 2014. 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 including The City of Seattle. On October 1, 2012, 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 a risk for “ripple claims” from other sellers, but the efficacy of these claims is currently being litigated and any potential impact to DYPM from ripple claims is impossible to predict at this stage.

Other Commitments and Contingencies

In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, design and construction, plant sites, power generation assets and LPG vessel charters. The following describes the more significant commitments outstanding at March 31, 2014.

Dam Safety Assessment Reports. In response to the failure of a CCR surface impoundment dike at the TVA’s Kingston Plant in Tennessee, the EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities. In March 2013, the EPA issued final dam safety assessment reports of the surface impoundments at our Baldwin and Hennepin facilities. The reports rate the impoundments at each facility as “poor,” meaning that a deficiency is recognized for a required loading condition in accordance with applicable dam safety criteria. A poor rating also applies when certain documentation is lacking or incomplete or if further critical studies are needed to identify any potential dam safety deficiencies. The reports include recommendations for further studies, repairs and changes in operational and maintenance practices. In July 2013, in response to the final report concerning Hennepin, we notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million. As a result of these changes, we increased our ARO by approximately $2 million during the second quarter 2013. We are performing additional recommended further studies and actions at Baldwin and Hennepin, some of which are dependent on necessary permits being obtained. The estimated cost for capital improvements to the Hennepin east dam is approximately $2 million. The nature and scope of repairs, if any, that ultimately may be needed at the Baldwin CCR surface impoundment is dependent on the results of the ongoing recommended studies. At this time, we are unable to estimate a reasonably possible cost, or range of costs, of repairs, but the repairs may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

New Source Review and Clean Air Litigation. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the NSR and NSPS provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment.

IPH Segment. Commencing in 2005, the IPH facilities received a series of information requests from the EPA pursuant to Section 114(a) of the CAA. The requests sought detailed operating and maintenance history data with respect to the Coffeen, Newton, Edwards, Duck Creek and Joppa facilities. In August 2012, the EPA issued a Notice of Violation alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated PSD, Title V permitting and other requirements. We believe our defenses to the allegations described in the Notice of Violation are meritorious. A recent decision by the U.S. Court of Appeals for the Seventh Circuit held that similar claims older than five years were barred by the statute of limitations. If not overturned, this decision may provide an additional defense to the allegations in the Newton facility Notice of Violation.

Ultimate resolution of these matters could have a material adverse impact on IPH’s future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters.

Edwards CAA Litigation. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. The District Court has scheduled the trial date for February 2016. IPH disputes the allegations and will defend the case vigorously. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter.

IPH Variance. In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting the variance relief to IPH. On January 17, 2014, we filed a Motion to Dismiss. On February 24, 2014, the Fourth District Appellate Court granted our motion and dismissed the appeal. On April 1, 2014, the environmental group filed a petition for leave to appeal the Appellate Court’s decision with the Illinois Supreme Court. We believe the variance was properly granted and that the Appellate Court’s judgment dismissing the petition for review was proper. We will vigorously defend our position, including opposing review by the Illinois Supreme Court.

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, or range of costs, of corrective action that ultimately may be required at Baldwin.

In April 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 at Vermilion, including post-closure care, was approximately $11 million. In March 2014, we submitted a revised corrective action plan for the old east impoundment at Vermilion. In light of the revised plan, our preliminary estimated cost of the recommended closure alternative for both Vermilion impoundments, including post-closure care, has been reduced to approximately $10 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 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 accordance with work plans approved by the Illinois EPA, in 2013 we performed a geotechnical study at Vermilion and began a 12-month geotechnical/hydraulic/hydrogeologic study needed to analyze corrective action alternatives at Baldwin. The geotechnical study at Vermilion confirmed that the cap closure option proposed in our corrective action plans for the north and old east CCR surface impoundmants is technically feasible. At this time we cannot reasonably estimate the costs of resolving these enforcement 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.

IPH Segment Groundwater. Hydrogeologic investigations of the CCR surface impoundments have been performed at the IPH segment facilities. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

In 2012, the Illinois EPA issued violation notices with respect to groundwater conditions at the Newton and Coffeen facilities’ CCR surface impoundments. In February 2013, the Illinois EPA provided written notice that it may pursue legal action with respect to each of these matters through referral to the Illinois Office of the Attorney General. In April 2013, AER filed a proposed rulemaking with the IPCB which, if approved, would provide for the systematic and eventual closure of AER’s ash ponds. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, preventative response, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The AER rulemaking has been stayed to allow the Illinois EPA proposed rulemaking to proceed. At this time we cannot reasonably estimate the costs or range of costs of resolving the Newton and Coffeen enforcement matters, but resolution of these matters may cause IPH to incur significant costs that could have a material adverse effect on its financial condition, results of operations and cash flows.

Station Power Proceedings. On May 4, 2010, the U.S. Court of Appeals for the District of Columbia 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. On October 25, 2013, PG&E filed revisions to its November 18, 2011 Advice Letter, seeking to limit retroactive charges to December 18, 2012 forward, rather than from April 2006 to present, as originally proposed. The October 2013 filing also proposed a 15-minute netting interval. On April 14, 2013, the CPUC’s Energy Division issued a draft resolution approving PG&E’s proposed station power charges, as modified by PG&E’s October 25, 2013 revisions. Comments on the draft resolution must be submitted to the Energy Division by May 5, 2014. The CPUC Commissioners are currently scheduled to vote on the draft resolution at the CPUC’s May 15, 2014 meeting. We believe we have established an appropriate accrual.

Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In June 2013, we amended our maintenance agreements. The term of the agreements will be determined by the maintenance cycles of the respective facility. We currently estimate these agreements will be in effect for a period of 15 or more years. Either party can terminate the agreements based on certain events as specified in the contracts. As of March 31, 2014, our minimum obligation with respect to these agreements is limited to the termination payments, which are approximately $149 million and $218 million in the event all contracts are terminated by us or the counterparty, respectively.

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, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote.

Indemnities

In connection with the LS Power Transaction, the sale of Illinois Power Company, the sale of our midstream business, and certain other sales transactions involving former assets, we entered into indemnifications regarding environmental, tax, employee and other representations. Even though Dynegy was discharged from any claims pursuant to the Plan and the order confirming the Plan (the “Confirmation Order”), several Dynegy subsidiaries remain jointly and severally liable for any indemnification claims depending on the terms of the applicable transaction agreement. Although certain of the indemnification obligations are indefinite, some have exceeded the survival period in the relevant transaction agreements or have exceeded the

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

applicable statute of limitations. In addition, some of these indemnification obligations are subject to individual thresholds and/or maximum aggregate limits depending on the terms of the transaction agreement. As of March 31, 2014, no claims have been made against us and we have not recorded a liability for these indemnities.

Guarantees

Limited Guaranty. In connection with the AER Acquisition, Dynegy has provided a Limited Guaranty of certain obligations of IPH up to $25 million. Concurrently with the execution of the AER Transaction Agreement, Dynegy entered into the Limited Guaranty, capped at $25 million in favor of Ameren, pursuant to which we guaranteed 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.

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, 2014, 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 $50 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

In addition, we are party to two charter agreements related to very large gas carriers (“VLGCs”) previously utilized in our former global liquids business. The primary term of one charter expired at the end of September 2013 but has been extended for a second consecutive year. The primary term of the second charter is through September 2014 but has been extended for a period of one year at the sole option of the counterparty. 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 $11 million for each of the years ended December 31, 2014 and 2015. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement.

Note 11—Related Party Transactions

Service Agreements. Certain of our Dynegy subsidiaries have Service Agreements with the DNE Debtor Entities. On October 1, 2012, Dynegy deconsolidated the DNE Debtor Entities. Our unaudited consolidated statements of operations include zero and $2 million of power purchased from our unconsolidated affiliate, which is reflected in Revenues for the three months ended March 31, 2014 and 2013, respectively. Please read Note 13—Related Party Transactions and Note 21—Emergence from Bankruptcy and Fresh-Start Accounting—Chapter 11 Filing and Emergence from Bankruptcy in our Form 10-K for further discussion.

Note 12—Income Taxes

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.

For the three months ended March 31, 2014, our overall effective tax rate on continuing operations of 7 percent was different than the statutory tax rate of 35 percent primarily due to a valuation allowance to eliminate our net deferred tax assets offset by the impact of expected alternative minimum tax for the 2014 tax year.

For the three months ended March 31, 2013, our overall effective tax rate on continuing operations of zero percent was different than the statutory tax rate of 35 percent primarily due to a valuation allowance to eliminate our net deferred tax assets, partially offset by the impact of state taxes.

As of March 31, 2014 and 2013, 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.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Note 13—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-employment benefits to retirees who meet age and service requirements which are more fully described in Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K.

The components of net periodic benefit cost (gain) were as follows:



	Pension Benefits						Other Benefits
	Three Months Ended March 31,
(amounts in millions)	2014			2013			2014			2013
Service cost benefits earned during period	$	3		$	2		$	—		$	—
Interest cost on projected benefit obligation	4			3			1			1
Expected return on plan assets	(5		)	(4		)	(1		)	—
Amortization of:
Prior service cost	—			—			(1		)	—
Net periodic benefit cost (gain)	$	2		$	1		$	(1	)	$	1

Note 14—Loss Per Share

The reconciliation of basic loss per share to diluted loss per share of our common stock outstanding during the three months ended March 31, 2014 and 2013 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 periods. Diluted loss per share represents the amount of losses for the periods 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 periods. Please read Note 17—Capital Stock in our Form 10-K for further discussion.



	Three Months Ended March 31,
(in millions, except per share amounts)	2014			2013
Net loss	$	(37	)	$	(142	)
Less: Net income attributable to noncontrolling interests	4			—
Net loss attributable to Dynegy Inc. for basic and diluted loss per share	$	(41	)	$	(142	)

Basic weighted-average shares	100			100
Effect of dilutive securities (1)	1			—
Diluted weighted-average shares	101			100

Loss per share attributable to Dynegy Inc.:
Basic	$	(0.41	)	$	(1.42	)
Diluted (1)	$	(0.41	)	$	(1.42	)

__________________________________________


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

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

For the three months ended March 31, 2014 and 2013, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:



	Three Months Ended March 31,
(in millions of shares)	2014	2013
Stock options	1.4	1.0
Restricted stock units	1.2	0.8
Performance stock units	0.3	0.1
Warrants	15.6	15.6
Total	18.5	17.5

Note 15—Condensed Consolidating Financial Information

On May 20, 2013, Dynegy issued the Senior Notes, as further described in Note 9—Debt. The 100 percent owned Subsidiary Guarantors, jointly, severally and unconditionally, guaranteed the payment obligations under the Senior Notes. Not all of Dynegy’s subsidiaries guarantee the Senior Notes including Dynegy’s indirect, wholly-owned subsidiary, IPH, which acquired AER and its subsidiaries on December 2, 2013. Prior to December 2, 2013, the non-guarantor subsidiaries were minor.

The following condensed consolidating financial statements present the financial information of (i) Dynegy (Parent), which is the parent and issuer, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Dynegy, (iii) the non-guarantor subsidiaries of Dynegy and (iv) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis.

These statements should be read in conjunction with the unaudited consolidated statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for financial information and does not include all disclosures included in annual financial statements.

For purposes of the Condensed Consolidating Financial Information, a portion of our intercompany receivable which we do not consider to be likely of settlement has been classified as equity as of March 31, 2014 and December 31, 2013.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Condensed Consolidating Balance Sheet as of March 31, 2014

(amounts in millions)



	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	570	$	158		$	268		$	—		$	996
Accounts receivable, net	44		160			291			(86		)	409
Intercompany receivable	—		407			33			(440		)	—
Inventory	—		73			108			—			181
Other current assets	8		140			105			(2		)	251
Total Current Assets	622		938			805			(528		)	1,837
Property, Plant and Equipment, Net	—		2,882			380			—			3,262
Other Assets
Investment in affiliates	6,347		—			—			(6,347		)	—
Other long-term assets	109		59			85			—			253
Intercompany note receivable	23		—			—			(23		)	—
Total Assets	$	7,101	$	3,879		$	1,270		$	(6,898	)	$	5,352
Current Liabilities
Accounts payable	$	—	$	163		$	293		$	(86	)	$	370
Intercompany payable	390		—			50			(440		)	—
Other current liabilities	119		193			147			(2		)	457
Total Current Liabilities	509		356			490			(528		)	827
Long-term debt	1,283		—			687			—			1,970
Intercompany interest payable	799		—			—			(799		)	—
Intercompany long-term debt	2,243		—			23			(2,266		)	—
Other long-term liabilities	97		149			139			—			385
Total Liabilities	4,931		505			1,339			(3,593		)	3,182
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,170		6,416			(69		)	(6,347		)	2,170
Intercompany receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,170		3,374			(69		)	(3,305		)	2,170
Noncontrolling interest	—		—			—			—			—
Total Equity	2,170		3,374			(69		)	(3,305		)	2,170
Total Liabilities and Equity	$	7,101	$	3,879		$	1,270		$	(6,898	)	$	5,352

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Condensed Consolidating Balance Sheet as of December 31, 2013

(amounts in millions)



	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	474	$	154		$	215		$	—		$	843
Accounts receivable, net	2		133			289			(4		)	420
Intercompany receivable	—		275			74			(349		)	—
Inventory	—		71			110			—			181
Other current assets	8		131			102			—			241
Total Current Assets	484		764			790			(353		)	1,685
Property, Plant and Equipment, Net	—		2,937			378			—			3,315
Other Assets
Investment in affiliates	6,453		—			—			(6,453		)	—
Other long-term assets	133		61			97			—			291
Total Assets	$	7,070	$	3,762		$	1,265		$	(6,806	)	$	5,291
Current Liabilities
Accounts payable	$	4	$	114		$	215		$	(4	)	$	329
Intercompany payable	299		—			50			(349		)	—
Other current liabilities	132		139			121			—			392
Total Current Liabilities	435		253			386			(353		)	721
Long-term debt	1,285		11			683			—			1,979
Intercompany interest payable	799		—			—			(799		)	—
Intercompany long-term debt	2,243		—			—			(2,243		)	—
Other long-term liabilities	98		145			141			—			384
Total Liabilities	4,860		409			1,210			(3,395		)	3,084
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,210		6,395			58			(6,453		)	2,210
Intercompany receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,210		3,353			58			(3,411		)	2,210
Noncontrolling interest	—		—			(3		)	—			(3		)
Total Equity	2,210		3,353			55			(3,411		)	2,207
Total Liabilities and Equity	$	7,070	$	3,762		$	1,265		$	(6,806	)	$	5,291

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2014

(amounts in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues	$	—		$	558		$	204		$	—	$	762
Cost of sales, excluding depreciation expense	—			(393		)	(159		)	—		(552		)
Gross margin	—			165			45			—		210
Operating and maintenance expense	—			(63		)	(47		)	—		(110		)
Depreciation expense	—			(58		)	(9		)	—		(67		)
General and administrative expense	(2		)	(14		)	(10		)	—		(26		)
Acquisition and integration costs	—			—			(6		)	—		(6		)
Operating income (loss)	(2		)	30			(27		)	—		1
Equity in losses from investments in affiliates	(17		)	—			—			17		—
Interest expense	(16		)	—			(14		)	—		(30		)
Other income and expense, net	(6		)	—			—			—		(6		)
Income (loss) from continuing operations before income taxes	(41		)	30			(41		)	17		(35		)
Income tax expense	—			(2		)	—			—		(2		)
Net income (loss)	(41		)	28			(41		)	17		(37		)
Less: Net income attributable to the noncontrolling interests	—			—			4			—		4
Income (loss) attributable to Dynegy Inc.	$	(41	)	$	28		$	(45	)	$	17	$	(41	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2014

(amounts in millions)



	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	(41	)	$	28	$	(41	)	$	17	$	(37	)
Other comprehensive income (loss) before reclassifications:
Actuarial loss, net of tax of zero	—			—		(3		)	—		(3		)
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service cost and actuarial loss, net of tax of zero	(1		)	—		—			—		(1		)
Other comprehensive income (loss) from investment in affiliates	(3		)	—		—			3		—
Other comprehensive income (loss), net of tax	(4		)	—		(3		)	3		(4		)
Comprehensive income (loss)	(45		)	28		(44		)	20		(41		)
Less: comprehensive income attributable to noncontrolling interests	(1		)	—		3			1		3
Total comprehensive income (loss) attributable to Dynegy Inc.	$	(44	)	$	28	$	(47	)	$	19	$	(44	)

Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2014

(amounts in millions)



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(9	)	$	140		$	35		$	—		$	166
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(6		)	(11		)	—			(17		)
Net intercompany transfers	113			—			—			(113		)	—
Net cash provided by (used in) investing activities	113			(6		)	(11		)	(113		)	(17		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs	(1		)	12			—			—			11
Repayments of borrowings	(2		)	—			—			—			(2		)
Net intercompany transfers	—			(142		)	29			113			—
Interest rate swap settlement payments	(4		)	—			—			—			(4		)
Other financing	(1		)	—			—			—			(1		)
Net cash provided by (used in) financing activities	(8		)	(130		)	29			113			4
Net increase in cash and cash equivalents	96			4			53			—			153
Cash and cash equivalents, beginning of period	474			154			215			—			843
Cash and cash equivalents, end of period	$	570		$	158		$	268		$	—		$	996

Note 16—Segment Information

We report the results of our operations in three segments: (i) Coal, (ii) IPH and (iii) Gas. The Coal segment includes DMG, which owns, directly and indirectly certain of our coal-fired power generation facilities. The IPH segment includes IPGC or Genco, which also owns, directly and indirectly, certain of our coal-fired power generation facilities. IPH also includes Illinois Power Resources Generating, LLC (“IPRG”) and our Homefield Energy retail business in Illinois. IPH and its direct and indirect subsidiaries and Genco and its direct and indirect subsidiaries are each organized into ring-fenced groups in order to maintain corporate separateness from the Gas and Coal segments. The Gas segment includes DPC, which owns, directly or indirectly, certain of our wholly-owned natural gas-fired power generation facilities. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). General and administrative expense is reported in Other for all periods presented.

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three months ended March 31, 2014 and 2013 is presented below:

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2014 and 2013

Segment Data as of and for the Three Months Ended March 31, 2014



(amounts in millions)	Coal			IPH			Gas			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	161		$	203		$	398		$	—		$	762
Intercompany revenues	(5		)	1			4			—			—
Total revenues	$	156		$	204		$	402		$	—		$	762

Depreciation expense	$	(14	)	$	(8	)	$	(44	)	$	(1	)	$	(67	)
General and administrative expense	—			—			—			(26		)	(26		)

Operating income (loss)	$	9		$	(16	)	$	34		$	(26	)	$	1

Interest expense													(30		)
Other items, net	—			—			—			(6		)	(6		)
Loss before income taxes													(35		)
Income tax expense													(2		)
Net loss													(37		)
Less: Net income attributable to noncontrolling interests													4
Net loss attributable to Dynegy Inc.													$	(41	)

Identifiable assets (domestic)	$	1,198		$	1,203		$	2,202		$	749		$	5,352
Capital expenditures	$	(3	)	$	(11	)	$	(2	)	$	(1	)	$	(17	)

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



(amounts in millions)	Coal			Gas			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	87		$	231		$	—		$	318
Total revenues	$	87		$	231		$	—		$	318

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

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

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

Identifiable assets (domestic)	$	1,234		$	2,716		$	432		$	4,382
Capital expenditures	$	(12	)	$	(8	)	$	—		$	(20	)

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended March 31, 2014 and 2013

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

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

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our unaudited consolidated financial statements: (i) the Coal segment (“Coal”), (ii) the IPH segment (“IPH”) and (iii) the Gas segment (“Gas”).

LIQUIDITY AND CAPITAL RESOURCES

Overview

In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations, cash on hand and amounts available under the revolver.

IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and our other legal entities. Certain of the entities in the IPH segment, including Genco, have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.

The following table summarizes our liquidity position at March 31, 2014:



	March 31, 2014
(amounts in millions)	Dynegy Inc.			IPH (1) (2)		Total
Revolver capacity	$	475		$	—	$	475
Less: Outstanding letters of credit	(166		)	—		(166		)
Revolver availability	309			—		309
Cash and cash equivalents	728			268		996
Total available liquidity (3)	$	1,037		$	268	$	1,305

__________________________________________


(1)	Includes Cash and cash equivalents of $191 million related to Genco.

Table of Contents


(2)	As previously discussed, due to the ring-fenced nature of IPH, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities.


(3)	On December 2, 2013, Dynegy and IPR entered into an intercompany revolving promissory note of $25 million. At March 31, 2014, there was $12 million drawn on the note.

Operating Activities

Historical Operating Cash Flows. Cash flow provided by operations totaled $166 million for the three months ended March 31, 2014. During the period, our power generation business provided cash of $151 million primarily due to the operation of our power generation facilities, partially offset by payments for acquisition and integration costs. Corporate and other operations used cash of approximately $31 million primarily due to interest payments to service debt related to our Credit Agreement and Senior Notes, employee-related payments and other general and administrative expense. This use of cash was partially offset by $46 million in positive changes in working capital, net of $38 million of increased collateral postings to satisfy our counterparty collateral demands.

Cash flow used in operations totaled $7 million for the three months ended March 31, 2013. During the period, our power generation business provided cash of $37 million primarily due to the operation of our power generation business, partially offset by $34 million in negative changes in working capital, which includes $9 million of increased collateral postings to satisfy our counterparty collateral demands. Corporate and other operations used cash of approximately $24 million primarily due to payments to advisors, employee-related payments and other general and administrative expense, partially offset by $14 million in positive changes in working capital.

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

Collateral Postings. We use a portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. The following table summarizes our collateral postings to third parties by legal entity at March 31, 2014 and December 31, 2013:



(amounts in millions)	March 31, 2014		December 31, 2013
Dynegy Inc.:
Cash (1)	$	38	$	22
Letters of credit	166		157
Total Dynegy Inc.	204		179

IPH:
Cash (1) (2)	18		7
Letters of credit (3)	10		—
Total IPH	28		7

Total	$	232	$	186

__________________________________________


(1)	Includes broker margin as well as other collateral postings included in Prepayments and other current assets on our unaudited consolidated balance sheets. At March 31, 2014 and December 31, 2013, $3 million and $4 million of cash posted as collateral were netted against Liabilities from risk management activities on our unaudited consolidated balance sheets, respectively.


(2)	Includes cash of $5 million and $1 million related to Genco at March 31, 2014 and December 31, 2013, respectively.


(3)	Relates to the $25 million cash-backed LC facility at IPM.

In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on assets already subject to first priority liens under our former and new credit agreements. The additional liens were granted as collateral under certain of our derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements.

Table of Contents

Collateral postings increased from December 31, 2013 to March 31, 2014 primarily due to new transactions and mark-to-market changes for fuel and other commodity purchases being executed with counterparties, ISO postings in support of our retail energy business and overall changes in our commercial activity.

The fair value of our derivatives collateralized by first priority liens included liabilities of $199 million and $145 million at March 31, 2014 and December 31, 2013, respectively.

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

Investing Activities

Capital Expenditures. We had capital expenditures of approximately $17 million and $20 million during the three months ended March 31, 2014 and 2013, respectively. These amounts include capitalized interest of $5 million and zero for the three months ended March 31, 2014 and 2013, respectively. Our capital spending by reportable segment was as follows:



(amounts in millions)	Three Months Ended March 31, 2014		Three Months Ended March 31, 2013
Coal	$	3	$	12
IPH	11		—
Gas	2		8
Other	1		—
Total	$	17	$	20

Other Investing Activities. During the three months ended March 31, 2014, we had no other investing activities. During the three months ended March 31, 2013, there was a $13 million cash inflow related to restricted cash balances related to the release of unused cash collateral associated with the DPC LC and DMG LC facilities. These proceeds were used to fund a portion of the repayments of the DMG and DPC credit agreements as further discussed below.

Financing Activities

Historical Cash Flow from Financing Activities. Cash flow provided by financing activities totaled $4 million for the three months ended March 31, 2014 due primarily to $12 million in proceeds received from a repurchase agreement related to emission credits, offset by $4 million in interest rate swap settlement payments, $2 million in principal payments of borrowings on the Tranche B-2 Term Loan and $1 million in financing costs in connection with the Credit Agreement and Senior Notes. Please read Note 9—Debt for further discussion.

Cash flow used in financing activities totaled $31 million for the three months ended March 31, 2013 due to $28 million in repayments of borrowings on the DMG and DPC credit agreements and $3 million in financing costs in connection with the DPC Revolving Credit Agreement.

Financing Trigger Events. Our debt instruments and certain of our other financial obligations and all the Genco Senior Notes include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and, in the case of the Credit Agreement, change of control provisions. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.

Table of Contents

Financial Covenants

Credit Agreement. On April 23, 2013, we entered into the Credit Agreement. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a financial covenant specifying required thresholds for our senior secured leverage ratio calculated on a rolling four quarters basis. Under the Credit Agreement, if Dynegy has utilized 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the following ratios for the respective periods:



Compliance Period		Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA (1)
September 30, 2013 through December 31, 2013		5.00: 1.00
March 31, 2014 through December 31, 2014		4.00: 1.00
March 31, 2015 through December 31, 2015		4.75: 1.00
March 31, 2016 through December 31, 2016		3.75: 1.00
March 31, 2017 and Thereafter		3.00: 1.00

__________________________________________


(1)	For purposes of calculating Net Debt, we may only apply a maximum of $150 million in cash to our outstanding secured debt.

Our revolver usage at March 31, 2014 was 35 percent of the aggregate revolver commitment due to outstanding letters of credit; therefore, we were required to test the covenant. Based on the calculation outlined in the Credit Agreement, we are in compliance at March 31, 2014.

Genco Senior Notes. On December 2, 2013, in connection with the AER Acquisition, Genco Senior Notes remained outstanding as an obligation of Genco, a subsidiary of IPH. Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates or to incur additional external, third-party indebtedness.

The following table summarizes these required ratios:



		Required Ratio
Restricted payment interest coverage ratio (1)		≥1.75
Additional indebtedness interest coverage ratio (2)		≥2.50
Additional indebtedness debt-to-capital ratio (2)		≤60%

__________________________________________


(1)	As of the date of a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.


(2)	Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Please read Note 9—Debt for further discussion.

Table of Contents

Credit Ratings

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



	Moody’s	S&P
Dynegy Inc.:
Corporate Family Rating	B2	B
Senior Secured	B1	BB-
Senior Unsecured	B3	B+
Genco:
Senior Unsecured	B3	CCC+

Table of Contents

RESULTS OF OPERATIONS

Overview

In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three months ended March 31, 2014 and 2013. At the end of this section, we have included our business outlook for each segment.

We report the results of our power generation business primarily as three separate segments in our unaudited consolidated financial statements: (i) Coal, (ii) IPH and (iii) Gas. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). General and administrative expense is reported in Other for all periods presented.

Consolidated Summary Financial Information — Three Months Ended March 31, 2014 Compared to Three Months Ended March 31, 2013

The following table provides summary financial data regarding our consolidated results of operations for the three months ended March 31, 2014 and 2013, respectively:



	Three Months Ended March 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(amounts in millions)	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	762		$	318		$	444		140	%
Cost of sales, excluding depreciation expense	(552		)	(284		)	(268		)	(94	)%
Gross margin	210			34			176			NM
Operating and maintenance expense	(110		)	(71		)	(39		)	(55	)%
Depreciation expense	(67		)	(54		)	(13		)	(24	)%
Gain on sale of assets, net	—			1			(1		)	(100	)%
General and administrative expense	(26		)	(22		)	(4		)	(18	)%
Acquisition and integration costs	(6		)	(3		)	(3		)	(100	)%
Operating income (loss)	1			(115		)	116			101	%
Interest expense	(30		)	(28		)	(2		)	(7	)%
Other income and expense, net	(6		)	1			(7		)	NM
Loss before income taxes	(35		)	(142		)	107			75	%
Income tax expense	(2		)	—			(2		)	(100	)%
Net loss	(37		)	(142		)	105			74	%
Less: Net income attributable to noncontrolling interests	4			—			4			100	%
Net loss attributable to Dynegy Inc.	$	(41	)	$	(142	)	$	101		71	%

The following tables provide summary financial data regarding our operating income (loss) by segment for the three months ended March 31, 2014 and 2013, respectively:



	Three Months Ended March 31, 2014
(amounts in millions)	Coal			IPH			Gas			Other			Total
Revenues	$	156		$	204		$	402		$	—		$	762
Cost of sales, excluding depreciation expense	(96		)	(159		)	(297		)	—			(552		)
Gross margin	60			45			105			—			210
Operating and maintenance expense	(37		)	(47		)	(27		)	1			(110		)
Depreciation expense	(14		)	(8		)	(44		)	(1		)	(67		)
General and administrative expense	—			—			—			(26		)	(26		)
Acquisition and integration costs (1)	—			(6		)	—			—			(6		)
Operating income (loss)	$	9		$	(16	)	$	34		$	(26	)	$	1

Table of Contents



	Three Months Ended March 31, 2013
(amounts in millions)	Coal			Gas			Other			Total
Revenues	$	87		$	231		$	—		$	318
Cost of sales, excluding depreciation expense	(115		)	(169		)	—			(284		)
Gross margin	(28		)	62			—			34
Operating and maintenance expense	(40		)	(30		)	(1		)	(71		)
Depreciation expense	(13		)	(40		)	(1		)	(54		)
Gain on sale of assets, net	1			—			—			1
General and administrative expense	—			—			(22		)	(22		)
Acquisition and integration costs (1)(2)	—			—			(3		)	(3		)
Operating loss	$	(80	)	$	(8	)	$	(27	)	$	(115	)

__________________________________________


(1)	Relates to costs associated with the AER Transaction Agreement. Please read Note 3—Acquisition for further discussion.


(2)	Acquisition and integration costs were captured in the Other segment prior to the closing of the AER Acquisition.

Discussion of Consolidated Results of Operations

Revenues. Revenues increased by $444 million from $318 million for the three months ended March 31, 2013 to $762 million for the three months ended March 31, 2014. Coal segment revenues increased by $69 million driven largely by higher realized prices and volumes in 2014. IPH segment revenues were $204 million on 6.7 million MWh of power generation. Gas segment revenues increased by $171 million driven largely by higher spark spreads and volumes primarily at Independence and Ontelaunee in 2014.

Cost of Sales. Cost of sales increased by $268 million from $284 million for the three months ended March 31, 2013 to $552 million for the three months ended March 31, 2014. Coal segment cost of sales decreased $19 million primarily due to $32 million in lower amortization costs associated with rail transportation contracts recorded in connection with the application of fresh-start accounting on the effective date of the Plan, partially offset by higher coal transportation costs due to a contracted price increase. IPH segment cost of sales were $159 million due to the AER Acquisition. Gas segment cost of sales increased $128 million driven by higher natural gas pricing and volumes in 2014. Cost of sales excludes depreciation expense.

Operating and Maintenance Expense. Operating and maintenance expense increased by $39 million from $71 million for the three months ended March 31, 2013 to $110 million for the three months ended March 31, 2014. The increase is primarily due to IPH segment costs of $47 million as a result of the AER Acquisition.

Depreciation Expense. Depreciation expense increased by $13 million from $54 million for the three months ended March 31, 2013 to $67 million for the three months ended March 31, 2014. The increase in depreciation expense was primarily related to a $1 million increase in the Coal segment, an $8 million increase in the IPH segment as the result of the AER Acquisition and a $4 million increase in the Gas segment due to various equipment retirements in three months ended March 31, 2014.

General and Administrative Expense. General and administrative expense increased by $4 million from $22 million for the three months ended March 31, 2013 to $26 million for the three months ended March 31, 2014. This increase is primarily due to higher labor and benefit costs associated with the AER Acquisition.

Acquisition and Integration Costs. Acquisition and integration costs increased by $3 million from $3 million for the three months ended March 31, 2013 to $6 million for the three months ended March 31, 2014 primarily related to the AER Acquisition. Please read Note 3—Acquisition for further discussion.

Interest Expense. Interest expense increased by $2 million from $28 million for the three months ended March 31, 2013 to $30 million for the three months ended March 31, 2014. This increase is primarily due to the interest related to the Credit Agreement and Genco Senior Notes in 2014, offset by interest related to the DPC and DMG credit agreements in 2013. Please read Note 12—Debt in our Form 10-K for further discussion.

Other Income and Expense, net. Other income and expense, net decreased by $7 million from income of $1 million for the three months ended March 31, 2013 to expense of $6 million for the three months ended March 31, 2014. The decrease in other income and expense, net consisted primarily of a $6 million loss due to a change in the fair value of our common stock warrants during the three months ended March 31, 2014.

Table of Contents

Income Tax Expense. We reported income tax expense from continuing operations of $2 million and zero for the three months ended March 31, 2014 and March 31, 2013, respectively. The increase in tax expense is primarily the result of accrued alternative minimum tax expected to be paid for the 2014 tax year.

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 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.

Net Income Attributable to Noncontrolling Interests. For the three months ended March 31, 2014, net income attributable to noncontrolling interests was $4 million related to our investment in EEI.

Discussion of Adjusted EBITDA

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

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

EBITDA and Adjusted EBITDA. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as interest rate swaps and warrants, (iii) the impact of impairment charges and certain other costs such as those associated with the acquisition of AER and (iv) income or expense on up front premiums received or paid for financial options in periods other than the strike periods.

We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges, gains and losses on sales of assets, and other items that could be considered “non-operating” or “non-core” in nature. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers, and other stakeholders that communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.

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

Table of Contents

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2014:



	Three Months Ended March 31, 2014
(amounts in millions)	Coal			IPH			Gas		Other			Total
Net loss attributable to Dynegy Inc.												$	(41	)
Income attributable to noncontrolling interest												4
Income tax expense												2
Interest expense												30
Other items, net												6
Operating income (loss)	$	9		$	(16	)	$	34	$	(26	)	$	1
Depreciation expense	14			8			44		1			67
Amortization of intangible assets and liabilities, net	(1		)	(1		)	18		—			16
Other items, net	—			—			—		(6		)	(6		)
EBITDA	22			(9		)	96		(31		)	78
Acquisition and integration costs	—			6			—		—			6
Mark-to-market loss, net	19			34			8		—			61
Change in fair value of common stock warrants	—			—			—		6			6
Income attributable to noncontrolling interest	—			(4		)	—		—			(4		)
Other	1			3			—		1			5
Adjusted EBITDA	$	42		$	30		$	104	$	(24	)	$	152

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2013:



	Three Months Ended March 31, 2013
(amounts in millions)	Coal			Gas			Other			Total
Net loss										$	(142	)
Interest expense										28
Other items, net										(1		)
Operating loss	$	(80	)	$	(8	)	$	(27	)	$	(115	)
Depreciation expense	13			40			1			54
Amortization of intangible assets and liabilities, net	31			32			—			63
Other items, net	—			1			—			1
EBITDA	(36		)	65			(26		)	3
Acquisition and integration costs	—			—			3			3
Mark-to-market (income) loss, net	40			(4		)	—			36
Other	—			—			1			1
Adjusted EBITDA	$	4		$	61		$	(22	)	$	43

Adjusted EBITDA

Adjusted EBITDA increased by $109 million from $43 million for the three months ended March 31, 2013 to $152 million for the three months ended March 31, 2014. The increase was primarily due to improved spark spreads in the Gas segment, improved energy prices for the Coal segment and the addition of the IPH segment.

Table of Contents

Discussion of Segment Adjusted EBITDA

Coal Segment. Realized prices were higher during the three months ended March 31, 2014 compared to the three months ended March 31, 2013, resulting in higher gross margin.

The following table provides summary financial data regarding our Coal segment results of operations for the three months ended March 31, 2014 and 2013, respectively:



	Three Months Ended March 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price information)	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Operating Revenues
Energy	$	218		$	119		$	99		83	%
Capacity	2			—			2			100	%
Mark-to-market loss, net	(19		)	(40		)	21			53	%
Other (1)	(45		)	8			(53		)	(663	)%
Total operating revenues	156			87			69			79	%
Operating Costs
Cost of sales	(97		)	(84		)	(13		)	(15	)%
Contract amortization	1			(31		)	32			103	%
Total operating costs	(96		)	(115		)	19			17	%
Gross margin	60			(28		)	88			314	%
Operating and maintenance expense	(37		)	(40		)	3			8	%
Depreciation expense	(14		)	(13		)	(1		)	(8	)%
Gain on sale of assets, net	—			1			(1		)	(100	)%
Operating income (loss)	9			(80		)	89			111	%
Depreciation expense	14			13			1			8	%
Amortization of intangible assets and liabilities, net	(1		)	31			(32		)	(103	)%
EBITDA	22			(36		)	58			161	%
Mark-to-market loss, net	19			40			(21		)	(53	)%
Other	1			—			1			100	%
Adjusted EBITDA	$	42		$	4		$	38		950	%

Million Megawatt Hours Generated (2)	5.3			5.0			0.3			6	%
In Market Availability for Coal-Fired Facilities (3)	88		%	89		%
Average Quoted Market Power Prices ($/MWh) (4):
On-Peak: Indiana (Indy Hub)	$	71.51		$	34.15		$	37.36		109	%
Off-Peak: Indiana (Indy Hub)	$	42.97		$	26.93		$	16.04		60	%

__________________________________________


(1)	For the three months ended March 31, 2014 and 2013, respectively, Other includes ($46) million and $10 million in financial settlements, $1 million and $1 million in ancillary services and $2 million and ($3) million in other miscellaneous items.


(2)	Reflects production volumes in million MWh generated.


(3)	In Market Availability is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


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

Operating income for the three months ended March 31, 2014 was $9 million compared to operating loss of $80 million for the three months ended March 31, 2013. Adjusted EBITDA totaled $42 million during the three months ended March 31, 2014

Table of Contents

compared to $4 million during the same period in 2013. The $38 million increase in Adjusted EBITDA resulted from higher realized prices in the three months ended March 31, 2014 compared to the same period in 2013.

Table of Contents

IPH Segment. The IPH segment includes the results of its wholesale and retail operations for the three months ended March 31, 2014. There were no operations during the three months ended March 31, 2013 as operations were acquired on December 2, 2013.



(dollars in millions, except for price information)	Three Months Ended March 31, 2014
Operating Revenues
Energy	$	213
Capacity	6
Mark-to-market loss, net	(34		)
Contract amortization	(9		)
Other (1)	28
Total operating revenues	204
Operating Costs
Cost of sales	(169		)
Contract amortization	10
Total operating costs	(159		)
Gross margin	45
Operating and maintenance expense	(47		)
Depreciation expense	(8		)
Acquisition and integration costs	(6		)
Operating loss	(16		)
Depreciation expense	8
Amortization of intangible assets and liabilities, net	(1		)
EBITDA	(9		)
Mark-to-market loss, net	34
Acquisition and integration costs	6
Income attributable to noncontrolling interest	(4		)
Other	3
Adjusted EBITDA	$	30

Million Megawatt Hours Generated (2)	6.7
In Market Availability for Coal-Fired Facilities (3)	90		%
Average Quoted Market Power Prices ($/MWh) (4):
On-Peak: Indiana (Indy Hub)	$	71.51
Off-Peak: Indiana (Indy Hub)	$	42.97

________________________________________


(1)	For the three months ended March 31, 2014, Other includes $26 million in financial settlements, ($1) million in ancillary services and $3 million in other miscellaneous items.


(2)	Reflects production volumes in million MWh generated.


(3)	In Market Availability is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


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

Operating loss for the three months ended March 31, 2014 was $16 million. Adjusted EBITDA totaled $30 million during the three months ended March 31, 2014, which consisted primarily of energy margin on 6.7 million MWh of power generation.

Table of Contents

Gas Segment. Spark spreads were higher in the three months ended March 31, 2014 compared to the three months ended March 31, 2013, particularly at Independence. The following table provides summary financial data regarding our Gas segment results of operations for the three months ended March 31, 2014 and 2013, respectively:



	Three Months Ended March 31,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price information)	2014			2013			Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Operating Revenues
Energy	$	416		$	169		$	247		146	%
Capacity	52			52			—			—	%
Mark-to-market income (loss), net	(8		)	3			(11		)	(367	)%
Contract amortization	(20		)	(34		)	14			41	%
Other (1)	(38		)	41			(79		)	(193	)%
Total operating revenues	402			231			171			74	%
Operating Costs
Cost of sales	(299		)	(171		)	(128		)	(75	)%
Contract amortization	2			2			—			—	%
Total operating costs	(297		)	(169		)	(128		)	(76	)%
Gross margin	105			62			43			69	%
Operating and maintenance expense	(27		)	(30		)	3			10	%
Depreciation expense	(44		)	(40		)	(4		)	(10	)%
Operating income (loss)	34			(8		)	42			525	%
Depreciation expense	44			40			4			10	%
Amortization of intangible assets and liabilities, net	18			32			(14		)	(44	)%
Other items, net	—			1			(1		)	(100	)%
EBITDA	96			65			31			48	%
Mark-to-market (income) loss, net	8			(4		)	12			300	%
Adjusted EBITDA	$	104		$	61		$	43		70	%

Million Megawatt Hours Generated (2)	4.5			4.3			0.2			5	%
In Market Availability for Combined Cycle Facilities (3)	99		%	97		%
Average Capacity Factor for Combined Cycle Facilities (4)	47		%	45		%
Average Market On-Peak Spark Spreads ($/MWh) (5)	$	29.87		$	13.15		$	16.72		127	%
Average Market Off-Peak Spark Spreads ($/MWh) (5)	$	(6.31	)	$	4.25		$	(10.56	)	(248	)%
Average natural gas price—Henry Hub ($/MMBtu) (6)	$	5.05		$	3.48		$	1.57		45	%

__________________________________________


(1)	For the three months ended March 31, 2014 and 2013, respectively, Other includes ($93) million and ($9) million in financial settlements, $37 million and $22 million in natural gas, $16 million and $8 million in ancillary services, $1 million and $16 million in tolls and $1 million and $4 million in RMR, option premiums and other miscellaneous items.


(2)	Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility.


(3)	In Market Availability is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. This calculation excludes certain events outside of management control such as weather related issues.


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


(5)	Reflects the average of our on- and off-peak spark spreads at the following facilities: Commonwealth Edison (NI Hub), PJM West, North of Path 15 (NP 15), New York - Zone A and Mass Hub.


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

Operating income for the three months ended March 31, 2014 was $34 million compared to a loss of $8 million for the three months ended March 31, 2013. Adjusted EBITDA totaled $104 million during the three months ended March 31, 2014

Table of Contents

compared to $61 million during the same period in 2013. The $43 million increase in Adjusted EBITDA primarily resulted from higher generation and spark spreads primarily at Independence and Ontelaunee and ancillary services across the Gas fleet, in the three months ended March 31, 2014 as compared to the same period in 2013. This increase was partially offset by a decrease in revenues generated on the Moss Landing toll.

Outlook

We expect that our future financial results will continue to be impacted by fuel and commodity prices, especially natural gas prices, which we anticipate will increase. Other factors to which our future financial results will remain sensitive include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is possible that we will experience additional costs associated with the handling and disposal of coal ash, how water used by our power generation facilities is withdrawn and treated before being discharged and more stringent air emission standards.

Coal. The Coal segment consists of four plants, all located in the MISO region, and totaling 2,980 MW.

As of May 2, 2014, our expected remaining generation volumes are 52 percent hedged volumetrically for 2014 and approximately 27 percent hedged volumetrically for 2015. We plan to continue our hedging program over a one- to three-year period using various instruments, which includes the sale of natural gas swaps as a cross-commodity correlated hedge for our power revenue. As a result of the offsetting risks of our Coal and Gas segments, we are able to reduce the costs associated with hedging by executing a portion of the hedges with an internal affiliate. The internal hedges are cross-commodity hedges and we intend to expand this in the future. Beyond 2014, the portfolio is largely open, positioning Coal to benefit from possible future power market pricing improvements.

Due to declining correlations between our plant LMP prices and trading hub prices, we plan to mitigate the risk of a breakdown between these prices through participation in FTR markets and busbar basis swaps to the extent they are economically available. Due to the limited availability of these instruments, hedge levels are likely to be lower than the hedge levels in prior years.

As of May 2, 2014, our expected coal requirements are 94 percent contracted and priced in 2014. Our forecasted coal requirements for 2015 are 64 percent contracted and 43 percent priced. Our coal transportation requirements are fully contracted and priced for the next several years. We continue to explore various alternative contractual commitments and financial options to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies.

The MISO filed proposed Resource Adequacy Enhancements with FERC on July 20, 2011. The FERC conditionally approved MISO’s proposal on June 11, 2012, leaving much of MISO’s proposal in place. The new tariff provisions replace the monthly construct with a full planning year product (June 1 - May 31) and further recognize zonal deliverability capacity requirements. The first zonal auction was held in March 2013. For the 2013-2014 planning year, capacity cleared at $1.05 per MW-day for all zones. This low clearing price was likely caused by excess capacity conditions prevailing in MISO for the term of the planning year.

On April 14, 2014, MISO released the results of the Planning Year 2014-2015 capacity auction. Local Resource Zone 4, in which our assets are located, cleared at $16.75 per MW-day, compared to $1.05 per MW-day for the previous Planning Year 2013-2014 capacity auction. In the future, the potential retirement of marginal MISO coal capacity due to poor economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM could also increase MISO capacity and energy pricing. As such, we expect to benefit from the 9.1 GW of MISO retirements by market participants that have been announced or retired to date.

Based on analysis of historical constraints near our generating facilities, we have identified opportunities to invest in transmission facilities upgrades which will help to mitigate the impact of congestion around our Baldwin plant. We are working with the Transmission Owner to potentially implement these upgrades. We continue to assess grid constraints impacting our other facilities to identify other opportunities to reduce congestion and improve LMPs at our Coal and newly acquired IPH facilities.

IPH. The IPH segment consists of five plants, totaling 4,062 MW. The Coffeen, Edwards, Duck Creek and Newton facilities are located in the MISO region. Joppa is located within its own control area, known as EEI. Joppa sells all of its net power into three connected control areas: MISO, TVA and LGE.

As of May 2, 2014, our IPH expected generation volumes are 79 percent hedged volumetrically for 2014 and approximately 52 percent hedged volumetrically for 2015. The IPH hedging program will continue to use our retail business, Homefield Energy, to hedge a portion of the output from our IPH facilities. The retail hedges are well correlated to our facilities due to the close

Table of Contents

proximity of the hedge and through participation in FTR markets. We also plan to use other instruments to hedge the power revenue. Homefield Energy’s ability to keep and possibly grow its existing market share will impact IPH’s hedge levels in the future.

As of May 2, 2014, our expected coal requirements for IPH are 96 percent contracted and 85 percent priced for 2014. Our forecasted coal requirements for 2015 are 40 percent contracted and 20 percent priced. Our coal transportation requirements are fully contracted and priced for the next several years. We continue to explore various alternative contractual commitments and financial options to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies.

Gas. The Gas segment consists of seven plants, geographically diverse in five markets, totaling 6,121 MW. Approximately 50 percent of our power plant capacity in the CAISO market is contracted through 2014 under tolling agreements with LSEs and a RMR agreement. A significant portion of the remaining capacity is sold as a resource adequacy product in the CAISO market. CAISO is anticipated to have greater capacity flexibility by 2015, which will provide us with increased opportunities from our California generation fleet.

The CAISO capacity market is a bilateral market in which load serving entities (LSEs) are required to procure sufficient resources to meet their peak load plus a fifteen percent reserve margin. The CAISO faces challenges to ensure system reliability and the ability to integrate renewables into the system given the state’s mandate to have 33 percent renewable resources by 2020. The CAISO and CPUC recently approved the Joint Reliability Plan in which the CAISO and CPUC will collaborate on several initiatives: (i) determination of multi-year resource adequacy procurement obligations for CPUC jurisdictional LSEs; (ii) development of a joint long-term planning assessment and (iii) development of a market-based reliability backstop mechanism to replace CPM (Capacity Procurement Mechanism), which is the administratively-priced mechanism currently used by CAISO. A flexible capacity requirement, to support renewable integration, has been imposed on CPUC jurisdictional LSEs and will be mandatory starting in 2015. The CAISO board recently approved the methodology and must offer obligations for flexible capacity developed through a stakeholder process. We do not anticipate a significant near term change in capacity prices given energy efficiency programs and distributed generation of residential and commercial roof top solar has kept energy demand growth has been relatively flat and CAISO studies on flexible capacity needs appear to show ample supplies through 2018.

The estimated useful lives of our generation facilities consider environmental regulations currently in place. With respect to Units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy. We are currently depreciating these units through 2024; however, depending on (i) a final determination of the compliance term and requirements of the California Water Intake Policy and (ii) our ability to secure energy and/or capacity contracts in the future, we could decide to reduce operations or cease to operate the units prior to 2024. The Morro Bay facility was retired on February 5, 2014; we are currently evaluating alternatives for the site.

On October 10, 2013, Dynegy and SCE agreed to resolve prior contract termination disputes by entering into two new transactions. The pending arbitration and federal court litigation have been dismissed as a result of the new transactions. Under the first transaction, SCE agreed to purchase energy and capacity from our Moss Landing Energy Facility for 2014 and 2015. Under the second transaction, SCE agreed to purchase energy and capacity from the same facility for 2016. The 2016 transaction is conditioned on approval by the CPUC, which both SCE and Dynegy have agreed to seek in good faith and use commercially reasonable efforts to obtain. On November 27, 2013, SCE filed the necessary request for the CPUC’s approval of the 2016 transaction. On April 16, 2014, the CPUC’s Energy Division issued its Draft Resolution approving the 2016 transaction without modification. The Draft Resolution is currently scheduled to be voted on by the Commissioners at the June 12, 2014 CPUC meeting.

In New England, eight forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity market in June 2010. The highest clearing price of $15 per kW-month occurred in the most recent auction for the 2017-2018 market period. However, the “insufficient competition” clause in the ISO-NE tariff was triggered, resulting in existing generation receiving an administrative cap price of $7.025 per kW-month. Due to oversupply conditions, the seven prior annual auctions cleared at the designated floor. Changes made to the forward capacity market design removed the auction floor price and implemented a minimum offer price rule that set a floor price for new entrants based on technology type. For the eighth auction, the floor price was removed. However, the auction cleared at the high mark, with existing generation receiving the administrative cap due to significant retirements in the region. ISO-NE is developing additional changes to the forward capacity market including performance incentives and a sloped demand curve which are expected to be in place for the ninth forward capacity auction in 2015.

In PJM, where the Kendall and Ontelaunee combined-cycle plants are located, ten forward capacity auctions (known as RPM or Reliability Pricing Model) have been held since the transition from a daily capacity market in June 2007. RPM clearing prices have ranged from $0.50 per kW-month (Kendall, 2012-2013 Planning Year) and $1.24 per kW-month (Ontelaunee, 2007-2008 Planning Year) to $5.30 per kW-month (Kendall, 2010-2011 Planning Year) and $6.88 per kW-month (Ontelaunee, 2013-2014

Table of Contents

Planning Year). The latest RPM auction was for the 2016-2017 Planning Year, which cleared at $1.81 per kW-month (Kendall) and $3.62 per kW-month (Ontelaunee). The next RPM auction, for the 2017-2018 Planning Year will be conducted in May 2014.

Capacity pricing for the NYISO seems to be recovering from the low point in 2011. The most recent summer and winter auctions have cleared higher than the previous auctions with summer 2014 at $5.15 per kW-month and winter 2013-2014 at $2.58 per kW-month for the rest of state market. We attribute the rebound in part to the FERC Order on buyer-side mitigation, affecting in-City resources, and retirements. For the balance of the year, approximately 75 percent of the capacity for our Independence facility has been contracted at a favorable premium compared to current market prices through October 31, 2014.

Excluding volumes subject to tolling agreements, as of May 2, 2014, our Gas portfolio is 55 percent hedged volumetrically through 2014 and approximately 21 percent hedged volumetrically for 2015. As a result of the offsetting risks of our Gas and Coal segments, we are able to reduce the costs associated with hedging by executing a portion of our natural gas hedges with an internal affiliate. We continue to manage our remaining commodity price exposure to changing fuel and power prices in accordance with our risk management policy.

Environmental and Regulatory Matters

Please read Item 1. Business-Environmental Matters in our Form 10-K for a detailed discussion of our environmental and regulatory matters.

The Clean Air Act

Cross-State Air Pollution Rule. On April 29, 2014, the U.S. Supreme Court issued a decision in EPA v. EME Homer City Generation, L.P. upholding the CSAPR. The Court reversed the judgment of the Court of Appeals for the District of Columbia Circuit, which had vacated the CSAPR in its entirety, finding the EPA’s CSAPR to be a reasonable interpretation of the CAA’s provisions addressing state contribution to air pollution in downwind states. The Court also remanded the decision to the court of appeals for further proceedings consistent with its decision. The EPA is expected to continue to administer the CAIR until a new rule addressing interstate air pollution transport is adopted or the CSAPR is reinstated following completion of judicial review.

Mercury/HAPs. On April 15, 2014, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision upholding the MATS rule for EGUs. Given the air emission controls already employed, we expect that each of our Coal segment facilities except Edwards Unit 1, as well as our IPH segment facilities, will be in compliance with the MATS rule emission limits without the need for significant additional investment. We continue to evaluate the ability of Edwards Unit 1 to meet the MATS limits until such time as MISO allows us retire the unit.

IPH Variance. In January 2014, an environmental group filed a petition for review in the Illinois Fourth District Appellate Court of the IPCB’s November 2013 decision and order granting IPH a variance to extend the applicable compliance dates for MPS SO₂ emission limits through December 31, 2019, subject to certain conditions. On January 17, 2014, we filed a Motion to Dismiss. On February 24, 2014, the Appellate Court granted our motion and dismissed the appeal. On April 1, 2014, the environmental group filed a petition for leave to appeal the Appellate Court’s decision with the Illinois Supreme Court. We believe the variance was properly granted and that the Appellate Court’s judgment dismissing the petition for review was proper. We will vigorously defend our position, including opposing review by the Illinois Supreme Court. Please read Note 10—Commitments and Contingencies for further discussion.

NAAQS. The EPA is in the process of completing its ongoing five-year review of the current ozone NAAQS, which may result in a more stringent standard. In February 2014, the EPA indicated that it anticipated taking final action regarding the ozone NAAQS by no later than November 2015.

Coal Handling Particulate Matter Emissions. In January 2014, the Illinois EPA proposed an emergency rule to address particulate matter emissions from the handling of petroleum coke and coal at bulk terminals and other specified facilities. On January 23, 2014, the IPCB denied the emergency rulemaking. In response, the Illinois EPA is developing a proposed rule to address such emissions in accordance with its general rulemaking authority and a proposed rule is expected to be released by fall 2014. In addition, the Illinois Office of the Attorney General is pursuing legislation to address particulate matter emissions from facilities handling petroleum coke or coal. While coal handling operations at our electric generating facilities would not be subject to such proposed standards, our Havana Dock coal handling facility potentially would be subject to the proposed standards, if adopted or enacted. At this time, we cannot predict the capital or operating costs potentially associated with compliance, but the cost of complying at our Havana Dock facility with any such new requirements, if adopted or enacted, could be significant.

Edwards Clean Air Litigation. In April 2013, environmental groups filed a citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. The District Court has scheduled the trial date for February 2016. We dispute the allegations and will defend the case vigorously. Please read Note 10—Commitments and Contingencies for further discussion.

Table of Contents

The Clean Water Act

Cooling Water Intake Structures. Under the terms of a settlement agreement, the EPA was to issue its final rule for cooling water intake structures at existing facilities by April 17, 2014. In April 2014, the EPA informed the court that it would not complete the rulemaking by that date but that it would take final action by May 16, 2014.

Our ultimate compliance approach with the final rule, once promulgated, at any particular facility will depend on numerous factors, including technology studies, compliance deadlines and implementation by the relevant state permitting authority. At this time, based on the requirements set forth in the EPA’s April 2011 proposed rule, we estimate the cost of our compliance with the rule would require an average of approximately $8 million annually over a five-year compliance period. This estimate assumes the EPA largely follows the proposed rule, the Baldwin and Duck Creek facilities’ cooling water is not classified as Waters of the U.S. and no new cooling towers are required. This estimate could change significantly depending upon a variety of factors, including the requirements of the final rule as promulgated.

California Water Intake Policy. The SACCWIS continues to assess the reliability impacts to the electric grid in connection with implementation of California’s Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling (the “Policy”). In its most recent draft annual report to the State Water Resources Control Board released in March 2014, the SACCWIS did not recommend any changes to the final compliance deadline in the Policy for any facility, but recognized that existing facilities may still require compliance date extensions. We continue to pursue our litigation challenging the Policy.

Effluent Limitation Guidelines. Under a modified consent decree, the EPA is required to take final action on its proposed revisions to the steam electric effluent limitation guidelines by September 30, 2015.

Other CWA Initiatives. On March 25, 2014, the EPA and the U.S. Army Corps of Engineers released a proposed rule that would define the term “waters of the United States,” which is used to determine the jurisdictional reach of the CWA. We are currently reviewing the proposed rule and our assessment of the proposed rule's potential impacts is ongoing.

Coal Combustion Residuals. The EPA is expected to issue a final CCR rule in late 2014 and intends to align its steam electric effluent limitation guidelines rule with the CCR rule. We are currently evaluating these proposed regulations to determine whether current management of CCR, including beneficial reuse, and the use of the CCR surface impoundments should be altered. We are also evaluating the potential costs to comply with these proposed regulations, which could be material, if such regulations are adopted. At this time, based on the requirements set forth in the EPA’s April 2010 Subtitle D CCR proposed rule and the EPA’s 2013 proposed effluent limitations guideline rule, we estimate the cost of our compliance with the CCR and effluent limitations guidelines rules would require an average of approximately $25 million annually over a five-year compliance period. This estimate assumes the EPA classifies CCR as “non-hazardous” and the final effluent limitations guideline rule is within the EPA’s four stated preferred options. This estimate also does not include the cost of compliance associated with closure of existing surface impoundments, which are addressed in our AROs. This estimate could change significantly depending upon a variety of factors, including the requirements of the final EPA rules as promulgated.

Climate Change

State Regulation of Greenhouse Gases. In April 2014, the CARB approved amendments to its GHG cap-and-trade program rule to address certain issues and provide additional clarity in implementation. We continue to monitor developments regarding the California cap-and-trade program and evaluate any potential impacts on our operations.

In March 2014, RGGI held its twenty-third auction, in which approximately 23 million allowances for the second control period were sold at a clearing price of $4.00 per allowance. RGGI’s next quarterly auction is scheduled for June 2014. We have participated in each of the quarterly RGGI auctions (or in secondary markets, as appropriate) to secure allowances for our affected assets.

We estimate the cost of RGGI allowances required to operate our affected facilities in New York and Maine during 2014 will be approximately $13 million. While the updated RGGI rules are expected to increase the cost of allowances required to operate our affected facilities in future years, we expect that the cost of compliance would be reflected in the power market and the actual impact to gross margin would be largely offset by an increase in revenue.

Table of Contents

RISK MANAGEMENT DISCLOSURES

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



(amounts in millions)	As of and for the Three Months Ended March 31, 2014
Fair value of portfolio at December 31, 2013	$	(62	)
Risk management losses recognized through the statement of operations in the period, net	(63		)
Contracts realized or otherwise settled during the period	11
Changes in collateral/margin netting	(1		)
Fair value of portfolio at March 31, 2014	$	(115	)

The net risk management liability of $115 million is the aggregate of the following line items on our unaudited consolidated balance sheets: Current Assets—Assets from risk management activities, Other Assets—Assets from risk management activities, Current Liabilities—Liabilities from risk management activities and Other Liabilities—Liabilities from risk management activities.

Risk Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of March 31, 2014, based on our valuation methodology:

Net Fair Value of Risk Management Portfolio



(amounts in millions)	Total			2014			2015			2016			2017			2018		Thereafter
Market quotations (1) (2)	$	(106	)	$	(73	)	$	(22	)	$	(11	)	$	(5	)	$	1	$	4
Prices based on models (2)	(12		)	(9		)	(3		)	—			—			—		—
Total (3)	$	(118	)	$	(82	)	$	(25	)	$	(11	)	$	(5	)	$	1	$	4

__________________________________________

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

(2) The market quotations category represents our transactions classified as Level 1 and Level 2. The prices based on models category represents transactions classified as Level 3. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.


(3)	Excludes $3 million of broker margin that has been netted against Risk Management liabilities on our unaudited consolidated balance sheets. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION

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

•

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


•	beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in natural gas prices, if any;


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


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

Table of Contents


•	the effects of, or changes to, MISO power procurement process;


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


•	efforts to secure retail sales and the ability to grow the retail business;


•	efforts to identify opportunities to reduce congestion and improve busbar power prices;


•	beliefs and assumptions about weather and general economic conditions;


•	projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;


•	expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios and other payments;


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


•	beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay and Vermilion facilities;


•	beliefs regarding successful renegotiation of the IBEW Local 1245 collective bargaining agreement;


•	beliefs regarding redevelopment efforts for the Morro Bay facility;


•	beliefs and assumptions regarding approval by the CPUC of the SCE 2016 transaction for Moss Landing Units 6 & 7;


•	ability to mitigate impacts associated with expiring RMR and/or capacity contracts;


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


•	anticipated benefits and expected synergies resulting from the AER Acquisition and beliefs associated with the integration of operations;


•	lack of comparable financial data due to the application of fresh-start accounting;


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


•	expectations regarding performance standards and capital and maintenance expenditures.

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

CRITICAL ACCOUNTING POLICIES

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

Item 3—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Please read Item 7A. Quantitative and Qualitative Disclosures About Market Risk in our Form 10-K for a discussion of our exposure to commodity price variability and other market risks related to our net non-trading derivative assets and liabilities, including foreign currency exchange rate risk. The following is a discussion of the more material of these risks and our relative exposures as of March 31, 2014.

Value at Risk (“VaR”). The following table sets forth the aggregate daily VaR of the mark-to-market portion of our risk management portfolio primarily associated with the Coal and Gas segments. The VaR calculation does not include market risks associated with the accrual portion of the risk management portfolio that is designated as “normal purchase, normal sale,” nor does it include expected future production from our generating assets. Please read “VaR” in our Form 10-K for a complete description of our valuation methodology. The daily and average VaR at March 31, 2014 compared to December 31, 2013 remained constant period over period.

Daily and Average VaR for Risk Management Portfolios



(amounts in millions)	March 31, 2014		December 31, 2013
One day VaR—95 percent confidence level	$	7	$	7
One day VaR—99 percent confidence level	$	9	$	10
Average VaR—95 percent confidence level for the rolling twelve months ended	$	4	$	4

Table of Contents

Credit Risk. The following table represents our credit exposure at March 31, 2014 associated with the mark-to-market portion of our risk management portfolio, on a net basis.

Credit Exposure Summary



(amounts in millions)	Investment Grade Quality		Non-Investment Grade Quality		Total
Type of Business:
Financial institutions	$	4	$	—	$	4
Oil and gas producers	1		—		1
Utility and power generators	7		—		7
Total	$	12	$	—	$	12

Interest Rate Risk

We are exposed to fluctuating interest rates related to our variable rate financial obligations, which consist of amounts outstanding under our Credit Agreement. We currently use interest rate swaps to mitigate this interest rate exposure. Our interest rate hedging instruments are recorded at their fair value. As a result of our outstanding interest rate derivatives, we do not have any significant exposure to changes in LIBOR.

The absolute notional amounts associated with our interest rate contracts were as follows at March 31, 2014 and December 31, 2013, respectively:



	March 31, 2014		December 31, 2013
Interest rate swaps (in millions of U.S. dollars) (1)	$	796	$	796
Fixed interest rate paid (percent)	3.15		3.15

_________________________________________


(1)	The calculation period for $250 million of the interest rate swaps began June 30, 2013, and the calculation period for the remaining $546 million began October 31, 2013.

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our CEO and our CFO, of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended). This evaluation included consideration of the various processes carried out under the direction of our disclosure committee. This evaluation also considered the work completed relating to our compliance with Section 404 of the Sarbanes-Oxley Act of 2002. Based on this evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2014.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the quarter ended March 31, 2014.

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

Please read Note 10—Commitments and Contingencies—Legal Proceedings to the accompanying unaudited consolidated financial statements for a discussion of the legal proceedings that we believe could be material to us.

Item 1A—RISK FACTORS

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

Item 6—EXHIBITS

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



Exhibit Number		Description
**10.1		Form of Non-Qualified Stock Option Award Agreement (2014 Awards).
**10.2		Form of Stock Unit Award Agreement - Officers (2014 Awards).
**10.3		Form of Performance Award Agreement (2014 Awards).
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**31.2		Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
†32.1		Chief Executive Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
†32.2		Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
**101.INS		XBRL Instance Document
**101.SCH		XBRL Taxonomy Extension Schema Document
**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document
**101.LAB		XBRL Taxonomy Extension Label Linkbase Document
**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

__________________________________________

** Filed herewith.

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

DYNEGY INC.

SIGNATURE

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



			DYNEGY INC.

Date:	May 8, 2014	By:	/s/ CLINT C. FREELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer