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 ~~September 30, 2015~~March 31, 2016

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 ¨

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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, ~~120,553,913~~117,278,604 shares outstanding as of ~~October~~April 19, ~~2015.~~2016.

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TABLE OF CONTENTS



		Page
DEFINITIONS		i

PART I. FINANCIAL INFORMATION

Item 1.	FINANCIAL STATEMENTS:
	Consolidated Balance Sheets as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015	1
	Consolidated Statements of Operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	3
	Consolidated Statements of Comprehensive ~~Income (Loss)~~Loss for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	4
	Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~	5
	Notes to Consolidated Financial Statements	6

Item 2.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	4736
Item 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	8060
Item 4.	CONTROLS AND PROCEDURES	8161

PART II. OTHER INFORMATION

Item 1.	LEGAL PROCEEDINGS	8262
Item 1A.	RISK FACTORS	82
~~Item 2.~~	~~UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~	8262
Item 6.	EXHIBITS	8364

SIGNATURE		8467

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DEFINITIONS

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



CAA		Clean Air Act
CAISO		The California Independent System Operator
~~CAA~~CPUC		~~Clean Air Act~~California Public Utility Commission
CT		Combustion Turbine
~~EGU~~		~~Electric Generating Units~~
EPA		Environmental Protection Agency
ERCOT		Electric Reliability Council of Texas
FCA		Forward Capacity Auction
FERC		Federal Energy Regulatory Commission
FTR		Financial Transmission Rights
IMA		In-market Asset Availability
IPCB		Illinois Pollution Control Board
IPH		IPH, LLC (formerly known as Illinois Power Holdings, LLC)
ISO		Independent System Operator
ISO-NE		Independent System Operator New England
kW		Kilowatt
LIBOR		London Interbank Offered Rate
MISO		Midcontinent Independent System Operator, Inc.
MMBtu		One Million British Thermal Units
Moody’s		Moody’s Investors Service Inc.
MW		Megawatts
MWh		Megawatt Hour
NM		Not Meaningful
NYISO		New York Independent System Operator
PJM		PJM Interconnection, LLC
PRIDE		Producing Results through Innovation by Dynegy Employees
RGGI		Regional Greenhouse Gas Initiative
RMR		Reliability Must Run
S&P		Standard & Poor’s Ratings Services
SEC		U.S. Securities and Exchange Commission

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PART I. FINANCIAL INFORMATION

Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	September 30, 2015			December 31, 2014			March 31, 2016		December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	934		$	1,870		$	821	$	505
Restricted cash	—			113			37		39
Accounts receivable, net of allowance for doubtful accounts of $2 and $2, respectively	436			270
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively							339		402
Inventory	531			208			579		597
Assets from risk management activities	69			78			177		100
Intangible assets	120			27			81		102
Prepayments and other current assets	177			108			247		187
Total Current Assets	2,267			2,674			2,281		1,932

Property, Plant and Equipment	9,269			3,685
Accumulated depreciation	(784		)	(430		)
Property, Plant and Equipment, Net	8,485			3,255			8,242		8,347
Other Assets
Investment in unconsolidated affiliate	189			—			185		190
Restricted cash	—			5,100
Assets from risk management activities	48			2			52		18
Goodwill	818			—			797		797
Intangible assets	82			38			44		62
Deferred income taxes	54			20
Other long-term assets	214			143			107		113
Total Assets	$	12,157		$	11,232		$	11,708	$	11,459

See the notes to consolidated financial statements.

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DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(unaudited) (in millions, except share data)


	September 30, 2015			December 31, 2014			March 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	315		$	216		$	243		$	292
Accrued interest	180			80			180			74
Deferred income taxes	67			20
Intangible liabilities	98			45			65			85
Accrued liabilities and other current liabilities	185			157			99			125
Liabilities from risk management activities	94			132			117			103
Asset retirement obligations							51			50
Debt, current portion	71			31			108			80
Total Current Liabilities	1,010			681			863			809
Debt, long-term portion	7,208			7,075			7,304			7,129
Other Liabilities
Liabilities from risk management activities	135			31			120			105
Asset retirement obligations	326			205			234			230
Deferred income taxes	26			—			44			29
Intangible liabilities	73			36			50			55
Other long-term liabilities	198			181			186			183
Total Liabilities	8,976			8,209			8,801			8,540
Commitments and Contingencies (Note 14)
Commitments and Contingencies (Note 13)

Stockholders’ Equity
Preferred stock, $0.01 par value, 20,000,000 shares authorized:
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding, respectively	400			400			400			400
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,179,226 shares issued and 123,182,927 shares outstanding at September 30, 2015; 124,436,941 shares issued and outstanding at December 31, 2014	1			1
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,566,819 shares issued and 117,240,697 shares outstanding at March 31, 2016; 128,228,477 shares issued and 116,902,355 outstanding at December 31, 2015							1			1
Additional paid-in capital	3,309			3,338			3,186			3,187
Accumulated other comprehensive income, net of tax	24			20			18			19
Accumulated deficit	(552		)	(736		)	(696		)	(686		)
Total Dynegy Stockholders’ Equity	3,182			3,023			2,909			2,921
Noncontrolling interest	(1		)	—			(2		)	(2		)
Total Equity	3,181			3,023			2,907			2,919
Total Liabilities and Equity	$	12,157		$	11,232		$	11,708		$	11,459

See the notes to consolidated financial statements.

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DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

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

Three Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 2014
Revenues $ 1,232
$ 615
$ 2,854
$ 1,898
Cost of sales, excluding depreciation expense (621 ) (387 ) (1,494 ) (1,304 )
Gross margin 611
228
1,360
594
Operating and maintenance expense (219 ) (114 ) (580 ) (360 )
Depreciation expense (174 ) (61 ) (413 ) (185 )
Impairments and other charges (74 ) —
(74 ) —
Gain (loss) on sale of assets, net —
3
(1 ) 17
General and administrative expense (29 ) (25 ) (94 ) (80 )
Acquisition and integration costs (8 ) (9 ) (121 ) (17 )
Operating income (loss) 107
22
77
(31 )
Earnings (losses) from unconsolidated investments (4 ) —
(1 ) 10
Interest expense (145 ) (32 ) (413 ) (104 )
Other income and expense, net 46
5
45
(40 )
Income (loss) before income taxes 4
(5 ) (292 ) (165 )
Income tax benefit (expense) (Note 15) (28 ) —
473
1
Net income (loss) (24 ) (5 ) 181
(164 )
Less: Net income (loss) attributable to noncontrolling interest —
—
(3 ) 5
Net income (loss) attributable to Dynegy Inc. (24 ) (5 ) 184
(169 )
Less: Dividends on preferred stock 5
—
16
—
Net income (loss) attributable to Dynegy Inc. common stockholders $ (29 ) $ (5 ) $ 168
$ (169 )

Earnings (Loss) Per Share (Note 18):
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders $ (0.23 ) $ (0.05 ) $ 1.33
$ (1.69 )
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders $ (0.23 ) $ (0.05 ) $ 1.31
$ (1.69 )

Basic shares outstanding 126
100
126
100
Diluted shares outstanding 126
100
140
100



	Three Months Ended March 31,
	2016			2015
Revenues	$	1,123		$	632
Cost of sales, excluding depreciation expense	(545		)	(377		)
Gross margin	578			255
Operating and maintenance expense	(221		)	(111		)
Depreciation expense	(171		)	(64		)
General and administrative expense	(37		)	(30		)
Acquisition and integration costs	(4		)	(90		)
Operating income (loss)	145			(40		)
Earnings from unconsolidated investments	2			—
Interest expense	(142		)	(136		)
Other income and (expense), net	1			(5		)
Income (loss) before income taxes	6			(181		)
Income tax expense (Note 14)	(16		)	—
Net loss	(10		)	(181		)
Less: Net loss attributable to noncontrolling interest	—			(1		)
Net loss attributable to Dynegy Inc.	(10		)	(180		)
Less: Dividends on preferred stock	5			5
Net loss attributable to Dynegy Inc. common stockholders	$	(15	)	$	(185	)

Loss Per Share (Note 17):
Basic and diluted loss per share attributable to Dynegy Inc. common stockholders	$	(0.13	)	$	(1.49	)

Basic and diluted shares outstanding	117			124

See the notes to consolidated financial statements.

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DYNEGY INC.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE ~~INCOME (LOSS)~~LOSS

(unaudited) (in millions)

Three Months Ended September 30, Nine Months Ended September 30,
2015 2014 2015 2014
Net income (loss) $ (24 ) $ (5 ) $ 181
$ (164 )
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax of $2, zero, $2 and zero, respectively) 13
—
8
(3 )
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, zero and zero, respectively) (1 ) (1 ) (3 ) (3 )
Other comprehensive income (loss), net of tax 12
(1 ) 5
(6 )
Comprehensive income (loss) (12 ) (6 ) 186
(170 )
Less: Comprehensive income (loss) attributable to noncontrolling interest 1
—
(2 ) 4
Total comprehensive income (loss) attributable to Dynegy Inc. $ (13 ) $ (6 ) $ 188
$ (174 )



	Three Months Ended March 31,
	2016			2015
Net loss	$	(10	)	$	(181	)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively)	(1		)	(1		)
Other comprehensive loss, net of tax	(1		)	(1		)
Comprehensive loss	(11		)	(182		)
Less: Comprehensive loss attributable to noncontrolling interest	—			(1		)
Total comprehensive loss attributable to Dynegy Inc.	$	(11	)	$	(181	)

See the notes to consolidated financial statements.

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DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited) (in millions)


	Nine Months Ended September 30,						Three Months Ended March 31,
	2015			2014			2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	181		$	(164	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Net loss							$	(10	)	$	(181	)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation expense	413			185			171			64
Non-cash interest expense	25			15			10			7
Amortization of intangibles	(18		)	38			14			(4		)
Risk management activities	(117		)	57			(109		)	(27		)
(Gain) loss on sale of assets, net	1			(17		)
Loss from unconsolidated investments	1			—
Earnings from unconsolidated investments							(2		)	—
Deferred income taxes	(473		)	(1		)	16			—
Impairment of long-lived assets	74			—
Change in value of common stock warrants	(43		)	43			(1		)	5
Other	37			27			13			11
Changes in working capital:
Accounts receivable, net	(48		)	187			65			1
Inventory	(52		)	1			18			(18		)
Prepayments and other current assets	95			32			28			(10		)
Accounts payable and accrued liabilities	227			(124		)	43			83
Distributions from unconsolidated investments	3			—
Changes in restricted cash							2			—
Changes in non-current assets	(23		)	(9		)	(70		)	(4		)
Changes in non-current liabilities	19			6			3			18
Net cash provided by operating activities	302			276
Net cash provided by (used in) operating activities							191			(55		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(171		)	(94		)	(65		)	(40		)
Proceeds from asset sales, net	—			17
Acquisitions, net of cash acquired	(6,078		)	—
Decrease in restricted cash	5,148			—
Distributions from unconsolidated affiliates	8			—			8			—
Other investing	(6		)	—
Net cash used in investing activities	(1,099		)	(77		)	(57		)	(40		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	88			12
Proceeds from long term borrowings							198			—
Repayments of borrowings	(29		)	(6		)	(5		)	(25		)
Financing costs from debt issuance	(31		)	(2		)
Financing costs from equity issuance	(6		)	—
Dividends paid	(17		)	—			(5		)	(7		)
Interest rate swap settlement payments	(13		)	(13		)	(4		)	(4		)
Repurchase of common stock	(127		)	—
Other financing	(4		)	(1		)	(2		)	(5		)
Net cash used in financing activities	(139		)	(10		)
Net cash provided by (used in) financing activities							182			(41		)
Net increase (decrease) in cash and cash equivalents	(936		)	189			316			(136		)
Cash and cash equivalents, beginning of period	1,870			843			505			1,870
Cash and cash equivalents, end of period	$	934		$	1,032		$	821		$	1,734
Other non-cash investing and financing activity:
Non-cash capital expenditures	$	9		$	36
Non-cash consideration transferred for Acquisitions	$	105		$	—
Non-cash capital expenditures pursuant to an equipment financing agreement	$	63		$	—

See the notes to consolidated financial statements.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

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 the Generally Accepted Accounting Principles of the United States of America (“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. Certain prior period amounts in our unaudited consolidated financial statements have been reclassified to conform to current year presentation. 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, ~~2014~~2015, filed with the SEC on February 25, ~~2015,~~2016, 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 unregulated 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). All significant intercompany transactions have been eliminated. Please read Note ~~20—~~19—Segment Information for further discussion.

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 (“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. Genco’s $825 million Senior Notes are non-recourse to Dynegy.

Note 2—Accounting Policies

Use of Estimates.The preparation of unaudited 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.

The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. There have been no significant changes to our accounting policies during the ~~nine~~three months ended ~~September 30, 2015. Due to our Acquisitions~~March 31, 2016.

Accounting Standards Adopted During the Current Period

Hybrid Financial Instruments. In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-16-Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in ~~April 2015 and~~a Hybrid Financial Instrument Issued in the ~~authorization~~Form of a ~~share repurchase program~~Share Is More Akin to Debt or Equity. The amendments in ~~August 2015, we have added~~this ASU clarify how current GAAP should be interpreted in evaluating the ~~following significant policies:~~

~~Undivided Interest Accounting.~~ ~~We account for our undivided interests~~economic characteristics and risks of a host contract in ~~certain of our coal-fired power generation facilities whereby our proportionate share of each facility’s assets, liabilities, revenues, and expenses are included~~a hybrid financial instrument that is issued in the ~~appropriate classifications in the accompanying unaudited consolidated financial statements.~~

~~Goodwill.~~ Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of net assets acquired. The carrying amount of our goodwill will be periodically reviewed, at least annually, for impairment and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In accordance with Accounting Standards Codification (“ASC”) 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment or we can directly perform a two-step impairment test. Based on our qualitative assessment, if we determine that the fair valueform of a ~~reporting unit is more likely than not~~share. Specifically, the amendments clarify that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the amendments clarify that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The amendments in this ASU also clarify that, in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (i.e., ~~a likelihood~~the relative strength of ~~more than 50 percent) to be less than its carrying amount,~~ the ~~two-step impairment test will be performed.~~debt-like or

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015

equity-like terms and ~~2014~~

Infeatures given the ~~absence~~facts and circumstances) when considering how to weight those terms and features. The adoption of ~~sufficient qualitative factors, goodwill impairment is determined using a two-step process:~~

Step one—Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two.

Step two—Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess.

~~Treasury Stock.~~ Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented on our unaudited consolidated balance sheet as a reduction of Additional paid-in capital.

~~Accounting Standards Adopted During the Current Period~~

~~Business Combinations.~~ ~~In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-16-Business Combinations (Topic 805). The amendments in~~ this ASU ~~require that~~on January 1, 2016 did not have an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this ASU require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted for financial statements that have not been issued. We adopted ASU 2015-16 as of September 30, 2015. Please see Note 3—Acquisitions for a summary of the impact on our unaudited consolidated financial statements.

~~Derivatives.~~ In August 2015, the FASB issued ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of locational marginal pricing by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our unaudited consolidated financial statements.

~~Inventory.~~ In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost and net realizable value (“NRV”), with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our unaudited consolidated financial statements.

~~Retirement Benefits.~~In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this ASU provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this ASU. The amendments in this ASU are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this ASU should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015.

~~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 ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

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 ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. The adoption of this ASU did not have a material impact on our unaudited consolidated financial statements or disclosures.

~~Accounting Standards Not Yet Adopted~~

Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for our debt issuance costs are not affected by the amendments in this update.

In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement.

~~The guidance in~~We adopted these ASUs ~~is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of these ASUs should be applied~~on January 1, 2016 on a retrospective basis affecting ~~all balance sheet periods presented. We do not anticipate~~presentation on the ~~adoption of these ASUs will have a material impact on our~~ unaudited consolidated balance ~~sheets.~~sheets for all periods presented.

Consolidation. In February 2015, the FASB issued ASU 2015-02-Consolidation (Topic 810). The amendments in this ASU respond to concerns about the current accounting for consolidation of certain legal entities, in particular: (i) consolidation of limited partnerships and similar legal entities, (ii) evaluating fees paid to a decision maker or a service provider as a variable interest, (iii) the effect of fee arrangements on the primary beneficiary determination, (iv) the effect of related parties on the primary beneficiary determination and (v) consolidation of certain investment funds. The ~~guidance in this ASU is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted in an interim period. We do not anticipate the~~ adoption of this ASU ~~will~~on January 1, 2016 did not have ~~a material~~an impact on our unaudited consolidated financial statements.

Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. ~~Reporting entities may elect~~The adoption of this ASU on January 1, 2016 did not have an impact on our unaudited consolidated financial statements.

Accounting Standards Not Yet Adopted

Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to ~~apply~~Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.

Debt Instruments. In March 2016, the FASB issued ASU 2016-06-Derivative and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments in this ASU clarify what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments ~~prospectively only, or retrospectively~~in this ASU is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The amendments are effective for ~~all prior~~public business entities for fiscal years beginning after December 15, 2016 and interim periods ~~presented~~within those fiscal years. All entities have the option of adopting the new requirements early, including adoption in an interim period. If an entity early adopts the ~~financial statements. Early adoption is permitted provided that the guidance is applied from~~new requirements in an interim period, it must reflect any adjustments as of the beginning of the fiscal year ~~of adoption.~~that includes that interim period. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board ~~(“IASB”)~~ jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU was further updated through the issuance of ASU 2015-14 in August ~~2015.~~2015 and ASU 2016-08 in March 2016. The amendments in ~~this~~ ASU 2015-14 develop a common revenue standard for GAAP and International Financial Reporting Standards ~~(“IFRS”)~~ by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements, and simplifying the preparation of financial statements. The amendments in ASU 2016-08 are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Note 3—Acquisitions

Acquisitions

~~ECP~~Delta Stock Purchase ~~Agreements.~~Agreement. On ~~April 1, 2015~~February 24, 2016, Atlas Power Finance, LLC (“Atlas” or the “Purchaser”), a wholly owned subsidiary of Atlas Power, LLC (“Atlas Power” or the “JV”), a newly formed limited liability company that is 65 percent indirectly owned by Dynegy and 35 percent owned by affiliated investment funds of Energy Capital Partners III, LLC (the ~~“EquiPower Closing Date”~~“ECP Funds”), ~~pursuant~~entered into a Stock Purchase Agreement, as amended (the “Delta Stock Purchase Agreement”) with GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), indirect subsidiaries of Engie S.A. Pursuant to, and subject to the terms and conditions of, the Delta Stock Purchase Agreement, the Purchaser will purchase from the Seller 100 percent of the issued and outstanding shares of common stock of GSENA, thereby acquiring approximately 8,700 MW in certain power generation facilities located in ERCOT, PJM, and ISO-NE for a base purchase ~~agreement dated August 21, 2014, as amended~~price of approximately $3.3 billion in cash, subject to certain adjustments (the ~~“ERC~~“Delta Transaction”).

The Delta Stock Purchase Agreement includes customary representations, warranties and covenants by the parties. The Delta Transaction is subject to various closing conditions, including (i) expiration of the applicable waiting period, which was received on April 1, 2016, under the Hart-Scott-Rodino Act; (ii) obtaining required approvals from the FERC and the Public Utility Commission of Texas; (iii) no injunction or other orders preventing the consummation of the transactions contemplated under the Delta Stock Purchase Agreement; (iv) the completion of GSENA’s internal reorganization in all material respects in accordance with an exhibit attached to the Delta Stock Purchase Agreement; (v) the continuing accuracy of each party’s representations and warranties and (vi) the satisfaction of other customary conditions. We expect the Delta Transaction to close in the fourth quarter of 2016 after satisfaction or waiver of these closing conditions.

Each party has agreed to indemnify the other for breaches of representations, warranties and covenants, and for certain other matters, subject to certain exceptions and limitations. The Delta Stock Purchase Agreement contains certain termination rights for both the Purchaser and the Seller, including if the closing does not occur within 12 months following the date of the Delta Stock Purchase Agreement. In the event the Delta Stock Purchase Agreement is terminated under certain circumstances, including the failure to obtain certain regulatory approvals, the Purchaser must pay GSENA a reverse termination fee of $132 million.

In connection with the Delta Transaction, each of Dynegy and the ECP Funds entered into equity commitment letters with the JV and the Purchaser, pursuant to which Dynegy and the ECP Funds have agreed to provide up to $1.185 billion ($770 million from Dynegy and $415 million from the ECP Funds) to the JV. Additionally, the JV has secured approximately $2.25 billion of committed debt facilities, including a $400 million junior bridge facility from the ECP funds and $1.85 billion of senior secured debt from a group of banks. These financings are non-recourse to Dynegy. We expect the JV to replace the $1.85 billion senior secured debt with permanent financing prior to the expected closing date of the Delta Transaction.

Also, on February 24, 2016, Dynegy entered into a Stock Purchase Agreement (the “PIPE Stock Purchase Agreement”) with Terawatt Holdings, LP (“Terawatt”), ~~our wholly-owned subsidiary,~~an affiliate of ECP Funds, pursuant to which Dynegy ~~Resource~~will, subject to the terms and conditions of the PIPE Stock Purchase Agreement, sell and issue to Terawatt at the closing of the Delta Transaction 13,711,152 shares of common stock, $0.01 par value per share, of Dynegy for an aggregate purchase price equal to $150 million (the “PIPE Transaction”). The closing of the PIPE Transaction is contingent on the closing of the Delta Transaction.

In addition, Dynegy has agreed to enter into an Investor Rights Agreement, in the form attached to the PIPE Stock Purchase Agreement (the “Investor Rights Agreement”), with Terawatt at the closing of the PIPE Transaction. Under the Investor Rights Agreement, Terawatt will be entitled to certain rights, including certain registration rights, rights of first refusal with respect to

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015

issuances of our common stock and the designation of one individual to serve on our Board of Directors as long as Terawatt and its affiliates own at least 10 percent of our common stock. Further, the Investor Rights Agreement subjects Terawatt to certain obligations, including certain voting obligations and customary standstill and lock-up periods.

Concurrently with the execution of the Delta Stock Purchase Agreement, each of Dynegy and one of the ECP Funds entered into limited guarantees in favor of GSENA to guarantee 65 percent and 35 percent, respectively, of the Purchaser’s obligation to pay the reverse termination fee of $132 million in accordance with the terms and conditions of the Delta Stock Purchase Agreement. Please read Note 13—Commitments and Contingencies for further discussion.

We incurred acquisition costs of $2 million for the three months ended March 31, 2016 related to the Delta Stock Purchase Agreement, which is included in Acquisition and integration costs in our unaudited consolidated statements of operations.

Energy Capital Partners (“ECP”) Purchase Agreements. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of a stock purchase agreement dated August 21, 2014,

as amended, our wholly-owned subsidiary, Dynegy Resource II, LLC ~~(the “ERC Purchaser”)~~ purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ~~Energy Capital Partners~~ECP (collectively, the “ERC Sellers”) thereby acquiring (i) five combined cycle natural gas-fired facilities in Connecticut, Massachusetts, and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas and oil-fired peaking facilities in Ohio, and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”).

On the EquiPower Closing Date, in a related transaction, pursuant to a stock purchase agreement and plan of merger dated August 21, 2014, as amended, ~~(the “Brayton Purchase Agreement” and together with the ERC Purchase Agreement, the “ECP Purchase Agreements”),~~ our wholly-owned subsidiary Dynegy Resource III, LLC ~~(the “Brayton Purchaser” and together with the ERC Purchaser, the “ECP Purchasers”)~~ purchased 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of ~~Energy Capital Partners~~ECP (collectively, the “Brayton Sellers” and together with the ERC Sellers, the “ECP Sellers”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”).

The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio, and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments. In aggregate, the resulting operations from the two coal-fired facilities acquired from the ECP Sellers are reported within our Coal segment, while related operations from the six natural gas-fired and two gas and oil-fired facilities are reported within our Gas segment.

Under the ECP Purchase Agreements, the ECP Purchasers and ECP Sellers have agreed to indemnify the other applicable parties for breaches of representations and warranties, breaches of covenants and certain other matters, subject to certain exceptions and limitations. Neither the ECP Purchasers nor the ECP Sellers, in the aggregate, are entitled to indemnification in excess of $276 million, and $104 million of the purchase price will be held in escrow for one year after closing to support the post-closing adjustment and the indemnification obligations of the ECP Sellers.

Duke Midwest Purchase Agreement. On April 2, 2015, ~~(the “Duke Midwest Closing Date”),~~ pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended (the “Duke Midwest Purchase Agreement”), our wholly-owned subsidiary Dynegy Resource I, LLC ~~(“DRI”)~~ purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation in (i) three combined cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) a retail energy business for a base purchase price of approximately ~~$2.80~~$2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments. We operate two of the five coal-fired facilities, the Miami Fort and Zimmer facilities, with other owners operating the three remaining facilities. The operations from the retail energy business, the five coal-fired and the one oil-fired facilities acquired from Duke Energy are reported within our Coal segment, while related operations from the five natural gas-fired facilities are reported within our Gas segment.

Under the Duke Midwest Purchase Agreement, DRI and Duke Energy have agreed to indemnify the other applicable parties for breaches of representations and warranties, breaches of covenants and certain other matters, subject to certain exceptions and limitations. Dynegy has guaranteed, up to a maximum liability of $2.80 billion, the obligations of DRI under the Duke Midwest Purchase Agreement and related Transition Services Agreement (“TSA”). DRI shall, in the aggregate, not be entitled to indemnification in excess of $280 million for most matters and $2.80 billion for certain fundamental representations, tax matters and fraud.

Business Combination Accounting. The EquiPower Acquisition and the Duke Midwest Acquisition (collectively, the “Acquisitions”) have been accounted for in accordance with ~~ASC~~Accounting Standards Codification (“ASC”) 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition dates, April 1, 2015 and April 2, 2015, respectively. The valuation of these assets and liabilities ~~are~~is classified as Level 3 within the fair value hierarchy levels. The initial accounting for the Acquisitions is not complete because certain information and analysis that may impact our initial ~~valuations are~~valuation is still being obtained or ~~reviewed as a result~~reviewed. Dynegy expects to finalize these amounts during the second quarter of ~~the short time period since the closing of the Acquisitions.~~2016. The significant assets and liabilities for which provisional amounts are recognized at the respective acquisition dates are property, plant and equipment ~~intangible assets and liabilities,~~(“PP&E”), goodwill, ~~investment in unconsolidated affiliate, working capital adjustments,~~ deferred income taxes and taxes other than deferred income taxes. We continue to evaluate settlements which could relate to pre-acquisition activity from the ISOs. Additionally, some taxes ~~and asset retirement obligations. The~~have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E, goodwill or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our ~~valuations are~~valuation is completed, not to exceed one year, and any material adjustments identified that existed as of the acquisition date will be recognized in the current period.

To fair value working capital, we used available market information. Asset retirement obligations were recorded in accordance with ASC 410. To fair value the acquired property, plant and equipment, we used a Discounted Cash Flow (“DCF”)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015

To fair value working capital, we used available market information. Asset retirement obligations (“AROs”) were recorded in accordance with ASC 410, Asset Retirement and ~~2014~~

Environmental Obligations. To fair value the acquired PP&E, we used a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model. ~~This~~The DCF model was created for each power generation facility based on its ~~estimated~~ remaining useful ~~life. The DCF model~~life, and included gross margin forecasts for each ~~power generation~~ facility ~~determined~~ using forward commodity market prices obtained from third party quotations for the years 2015 ~~through~~and 2016. For the years 2017 through 2024, we used gross margin forecasts based upon commodity and capacity price curves developed internally ~~utilizing~~using forward ~~NYMEX~~New York Mercantile Exchange natural gas prices and supply and demand factors. For periods beyond 2024, we assumed a 2.5 percent growth rate. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for the years 2015 through 2019 and assumed a 2.5 percent growth rate, based upon management’s view of future conditions, thereafter. The resulting cash flows were then discounted using plant specific discount rates of approximately 8 percent to 10 percent for gas-fired generation facilities and approximately 9 percent to 13 percent for coal-fired generation facilities, based upon the asset’s age, efficiency, region and years until retirement. Contracts with terms that were not at current market prices were also valued using a DCF analysis. The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability. The 3,460,053 shares of common stock of Dynegy, issued as part of the consideration for the EquiPower Acquisition, were valued at approximately $105 million based on the closing price of Dynegy’s common stock on the EquiPower Closing Date.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015:

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~


(amounts in millions)	EquiPower Acquisition		Duke Midwest Acquisition			Total		EquiPower Acquisition		Duke Midwest Acquisition			Total
Cash	$	3,350	$	2,800		$	6,150	$	3,350	$	2,800		$	6,150
Equity instruments (3,460,053 common shares of Dynegy)	105		—			105		105		—			105
Net working capital adjustment	206		(9		)	197		206		(9		)	197
Fair value of total consideration transferred	$	3,661	$	2,791		$	6,452	$	3,661	$	2,791		$	6,452

Cash	$	267	$	—		$	267	$	267	$	—		$	267
Accounts receivable	47		124			171		49		126			175
Inventory	166		105			271		167		105			272
Assets from risk management activities (including current portion of $4 million and $30 million, respectively)	4		33			37		4		33			37
Prepayments and other current assets	32		69			101		32		69			101
Property, plant and equipment	2,769		2,740			5,509		2,773		2,734			5,507
Investment in unconsolidated affiliate	201		—			201		200		—			200
Intangible assets (including current portion of $67 million and $36 million, respectively)	111		84			195		111		84			195
Other long-term assets	28		34			62		28		35			63
Total assets acquired	3,625		3,189			6,814		3,631		3,186			6,817

Accounts payable	27		92			119		27		96			123
Accrued liabilities and other current liabilities	21		11			32		22		10			32
Debt, current portion	39		—			39		39		—			39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)	57		107			164		57		107			164
Asset retirement obligations	52		53			105		43		49			92
Intangible liabilities (including current portion of $24 million and $58 million, respectively)	73		93			166		73		93			166
Deferred income taxes, net	513		—			513		506		—			506
Other long-term liabilities	—		42			42		—		40			40
Total liabilities assumed	782		398			1,180		767		395			1,162
Identifiable net assets acquired	2,843		2,791			5,634		2,864		2,791			5,655
Goodwill	818		—			818		797		—			797
Net assets acquired	$	3,661	$	2,791		$	6,452	$	3,661	$	2,791		$	6,452

As a result of recording the stepped up fair market basis for GAAP purposes, but receiving primarily carryover basis for tax purposes in the EquiPower Acquisition, we recorded a net deferred tax liability of $537 million within our provisional valuation of the EquiPower Acquisition for the period ended June 30, 2015. As we had previously recorded a valuation allowance against our historical deferred tax assets, we released approximately $480 million of our valuation allowance as a result of these increased net deferred tax liabilities in the three months ended June 30, 2015. Due to the availability of new information related to the EquiPower Acquisition, we reduced the deferred tax liability in the three months ended September 30, 2015 by $24 million, offset by a corresponding reduction to goodwill. This reduction to the deferred tax liability resulted in a partial reversal of the previously recognized release of the valuation allowance by $21 million. The initial release of the valuation allowance and the partial reversal were recorded as Income tax benefit (expense) in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015.

The goodwill of $818 million resulting from the EquiPower Acquisition reflects the excess of our purchase price over the fair value of the net assets acquired. We allocated all of the goodwill to our Gas reporting unit. None of the goodwill recognized is deductible for income tax purposes, and as such, no deferred taxes have been recorded related to goodwill. No goodwill was recognized as a result of the Duke Midwest Acquisition.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

We incurred acquisition costs of ~~$1 million~~zero and ~~$86~~$90 million for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, respectively, related to the Acquisitions, which are included in Acquisition and integration costs in our unaudited consolidated ~~statement~~statements of operations. Acquisition costs for the ~~nine~~three months ended ~~September 30,~~March 31, 2015 ~~include~~included $42 million in acquisition advisory and consulting fees and $48 million ofin commitment fees associated with a temporary bridge facility, which were payable only upon the closing of the Acquisitions. No amounts were borrowed under the bridge facility, and the bridge facility was cancelled asupon our execution of the permanent financing for the ~~Acquisitions was executed.~~Acquisitions. Revenues of ~~$589 million and $1,071~~$661 million and operating income of ~~$91 million and $133~~$157 million attributable to the Acquisitions for the three ~~and nine~~ months ended ~~September 30, 2015, respectively,~~March 31, 2016 are included in our unaudited consolidated ~~statement~~statements of operations.

Pro Forma Results. The unaudited pro forma financial results for the ~~nine~~three months ended ~~September 30,~~March 31, 2015 ~~and 2014~~ assume the EquiPower Acquisition and the Duke Midwest Acquisition occurred on January 1, 2014. 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, 2014, nor are they indicative of future results of operations.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

Nine Months Ended September 30,
(amounts in millions) 2015 2014
Revenues $ 3,844
$ 4,155
Net income (loss) $ 442
$ (555 )
Net income (loss) attributable to noncontrolling interests $ (3 ) $ 5
Net income (loss) attributable to Dynegy Inc. $ 445
$ (560 )



(amounts in millions)	Three Months Ended March 31, 2015
Revenues	$	1,622
Net income	$	80
Net loss attributable to noncontrolling interests	$	(1	)
Net income attributable to Dynegy Inc.	$	81

Note 4—Unconsolidated Investments

Equity Method Investments

Elwood. In connection with the EquiPower Acquisition, we acquired a 50 percent interest in Elwood Energy LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (“Elwood Expansion” and, together with Elwood Energy, “Elwood”). Elwood Energy owns a 1,576 MW natural gas-fired facility located in Elwood, Illinois. ~~As of September 30,~~At March 31, 2016 and December 31, 2015, our equity method investment included in our unaudited consolidated balance ~~sheet~~sheets was ~~$189 million.~~$185 million and $190 million, respectively. Upon the acquisition of our Elwood investment, we recognized basis differences in the net assets of approximately ~~$90~~$89 million related to ~~property plant and equipment,~~working capital, PP&E, debt, and intangibles. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. Holders of the debt of our unconsolidated investment do not have recourse to us and our other subsidiaries; therefore, the debt of our unconsolidated investment is not reflected in our unaudited consolidated balance ~~sheet.~~sheets.

We recorded ~~$4 million and $1~~$2 million in equity ~~losses~~earnings related to our investment in Elwood, which is reflected in Earnings ~~(losses)~~ from unconsolidated investments in our unaudited consolidated statement of operations for the three ~~and nine~~ months ended ~~September 30, 2015.~~March 31, 2016. For the three months ended ~~September 30, 2015,~~March 31, 2016, we received a distribution of ~~$11~~$8 million, all of which ~~$8 million~~ was considered a return of investment. ~~As of September 30,~~At March 31, 2016 and December 31, 2015, we have ~~approximately $4~~$2 million and $3 million in accounts receivable due from Elwood, respectively, which is included in Accounts receivable in our unaudited consolidated balance ~~sheet.~~sheets.

~~Black Mountain.~~ On June 27, 2014, we completed the sale of our 50 percent partnership interest in Nevada Cogeneration Associates #2, a partnership that owns Black Mountain, an 85 MW (43 net MW) natural gas-fired combined cycle gas turbine facility in Nevada. We received $3 million and $14 million in cash proceeds upon the close of the transaction, which is reflected in Gain on sale of assets, net in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2014. In connection with the sale, our guarantee was terminated. Additionally, we received $10 million in cash distributions from Black Mountain, which is recorded as Earnings (losses) from unconsolidated investments in our unaudited consolidated statements of operations for the nine months ended September 30, 2014.

Note 5—Risk Management Activities, Derivatives, and Financial Instruments

The nature of our business necessarily involves commodity 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 and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Our commodity risk management policy 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 have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases and retail power sales which 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,” in accordance with ASC ~~815.~~815, Derivatives and Hedging. 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.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

Quantitative Disclosures Related to Financial Instruments and Derivatives

As of ~~September 30, 2015~~March 31, 2016, we had net purchases and sales of derivative contracts outstanding in the following quantities:


Contract Type	Quantity		Unit of Measure	Fair Value (1)			Quantity		Unit of Measure	Fair Value (1)
(dollars and quantities in millions)	Purchases (Sales)			Asset (Liability)			Purchases (Sales)			Asset (Liability)
Commodity contracts:
Electricity derivatives (2)	(46	)	MWh	$	(25	)	(50	)	MWh	$	148
Electricity basis derivatives (3)	(40	)	MWh	$	40		(7	)	MWh	$	3
Natural gas derivatives (2)	313		MMBtu	$	(133	)	362		MMBtu	$	(168	)
Natural gas basis derivatives	67		MMBtu	$	(12	)	83		MMBtu	$	(3	)
Diesel fuel derivatives	4		Gallon	$	(5	)
Diesel fuel							2		Gallon	$	(3	)
Coal derivatives (4)	—		Metric Ton	$	(30	)	—		Metric Ton	$	(15	)
Heat rate derivatives	2		MWh/MMBtu	$	(2	)
Emissions derivatives	6		Metric Ton	$	5		4		Metric Ton	$	(3	)
Interest rate swaps	779		U.S. Dollar	$	(48	)	775		U.S. Dollar	$	(46	)
Common stock warrants (5)	16		Warrant	$	(18	)	16		Warrant	$	(6	)


(1)	Includes both asset and liability risk management positions, but excludes margin and collateral netting of ~~$98~~$79 million.


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


(3)	Comprised of FTRs and swaps.


(4)	Our net position rounds to less than 1 million tons.


(5)	Each warrant is convertible into one share of Dynegy common stock.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Derivatives on the Balance Sheet. The following tables present the fair value and balance sheet classification of derivatives in ~~the~~our unaudited consolidated balance sheets as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015. As of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015, there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets.


			September 30, 2015													March 31, 2016
						Gross amounts offset in the balance sheet													Gross amounts offset in the balance sheet
Contract Type	Contract Type	Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value			Contract Type	Location on Balance Sheet	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)	(amounts in millions)													(amounts in millions)
Derivative assets:	Derivative assets:													Derivative assets:
	Commodity contracts	Assets from risk management activities	$	423		$	(306	)	$	—	$	117		Commodity contracts	Assets from risk management activities	$	653		$	(424	)	$	—	$	229
	Total derivative assets		$	423		$	(306	)	$	—	$	117		Total derivative assets		$	653		$	(424	)	$	—	$	229

Derivative liabilities:	Derivative liabilities:													Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(585	)	$	306		$	98	$	(181	)	Commodity contracts	Liabilities from risk management activities	$	(694	)	$	424		$	79	$	(191	)
	Interest rate contracts	Liabilities from risk management activities	(48		)	—			—		(48		)	Interest rate contracts	Liabilities from risk management activities	(46		)	—			—		(46		)
	Common stock warrants	Other long-term liabilities	(18		)	—			—		(18		)	Common stock warrants	Other long-term liabilities	(6		)	—			—		(6		)
	Total derivative liabilities		$	(651	)	$	306		$	98	$	(247	)	Total derivative liabilities		$	(746	)	$	424		$	79	$	(243	)
Total derivatives	Total derivatives		$	(228	)	$	—		$	98	$	(130	)	Total derivatives		$	(93	)	$	—		$	79	$	(14	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015


			December 31, 2014													December 31, 2015
						Gross amounts offset in the balance sheet													Gross amounts offset in the balance sheet
Contract Type	Contract Type	Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value			Contract Type	Location on Balance Sheet	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)	(amounts in millions)													(amounts in millions)
Derivative assets:	Derivative assets:													Derivative assets:
	Commodity contracts	Assets from risk management activities	$	115		$	(35	)	$	—	$	80		Commodity contracts	Assets from risk management activities	$	403		$	(285	)	$	—	$	118
	Total derivative assets		$	115		$	(35	)	$	—	$	80		Total derivative assets		$	403		$	(285	)	$	—	$	118

Derivative liabilities:	Derivative liabilities:													Derivative liabilities:
	Commodity contracts	Liabilities from risk management activities	$	(163	)	$	35		$	9	$	(119	)	Commodity contracts	Liabilities from risk management activities	$	(557	)	$	285		$	106	$	(166	)
	Interest rate contracts	Liabilities from risk management activities	(44		)	—			—		(44		)	Interest rate contracts	Liabilities from risk management activities	(42		)	—			—		(42		)
	Common stock warrants	Other long-term liabilities	(61		)	—			—		(61		)	Common stock warrants	Other long-term liabilities	(7		)	—			—		(7		)
	Total derivative liabilities		$	(268	)	$	35		$	9	$	(224	)	Total derivative liabilities		$	(606	)	$	285		$	106	$	(215	)
Total derivatives	Total derivatives		$	(153	)	$	—		$	9	$	(144	)	Total derivatives		$	(203	)	$	—		$	106	$	(97	)

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position that are not fully collateralized (excluding transactions with our clearing brokers that are fully collateralized) ~~at September 30, 2015 was $55~~as of March 31, 2016 is $35 million for which we have posted ~~$10~~$21 million in collateral. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

The following table summarizes our ~~total~~ cash collateral posted as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015, ~~along with the location~~within Prepayments and other current assets on ~~the~~our unaudited consolidated balance ~~sheet~~sheets, and the amount applied against ~~our~~ short-term risk management ~~liabilities.~~activities:


Location on balance sheet	September 30, 2015		December 31, 2014
Location on Balance Sheet					March 31, 2016		December 31, 2015
(amounts in millions)
Gross collateral posted with counterparties	$	148	$	49	$	140	$	162
Less: Collateral netted against risk management liabilities	98		9		79		106
Net collateral within Prepayments and other current assets	$	50	$	40	$	61	$	56

Impact of Derivatives on the Unaudited Consolidated Statements of Operations

The following discussion and ~~tables~~table 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 our unaudited consolidated statements of operations.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

Our unaudited consolidated statements of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ include the impact of derivative financial instruments as presented ~~below.~~below:


Derivatives Not Designated as Hedges	Location of Gain (Loss) Recognized in Income on Derivatives	Three Months Ended September 30,						Nine Months Ended September 30,						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	2015			2014			2015			2014			Location of Gain (Loss) Recognized in Income on Derivatives	2016			2015
(amounts in millions)
Commodity contracts	Revenues	$	48		$	(3	)	$	120		$	(212	)	Revenues	$	192		$	19
Interest rate contracts	Interest expense	$	(9	)	$	1		$	(17	)	$	(6	)	Interest expense	$	(8	)	$	(9	)
Common stock warrants	Other income (expense), net	$	45		$	6		$	43		$	(43	)	Other income and (expense), net	$	1		$	(5	)

Note 6—Fair Value Measurements

We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used the same valuation techniques for all periods presented. Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements in our Form 10-K for further discussion.

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015 and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin ~~paid.~~paid:



	Fair Value as of March 31, 2016
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	515		$	47		$	562
Natural gas derivatives	—			67			14			81
Emissions derivatives	—			1			—			1
Coal derivatives	—			7			2			9
Total assets from commodity risk management activities	$	—		$	590		$	63		$	653
Liabilities:										.
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(347	)	$	(64	)	$	(411	)
Natural gas derivatives	—			(220		)	(32		)	(252		)
Emissions derivatives	—			(4		)	—			(4		)
Diesel fuel derivatives	—			(3		)	—			(3		)
Coal derivatives	—			(23		)	(1		)	(24		)
Total liabilities from commodity risk management activities	—			(597		)	(97		)	(694		)
Liabilities from interest rate contracts	—			(46		)	—			(46		)
Liabilities from outstanding common stock warrants	(6		)	—			—			(6		)
Total liabilities	$	(6	)	$	(643	)	$	(97	)	$	(746	)

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Fair Value as of September 30, 2015
(amounts in millions) Level 1 Level 2 Level 3 Total
Assets:

Assets from commodity risk management activities:

Electricity derivatives $ —
$ 257
$ 102
$ 359
Natural gas derivatives —
43
5
48
Emissions derivatives —
5
—
5
Coal derivatives —
7
4
11
Total assets from commodity risk management activities $ —
$ 312
$ 111
$ 423
Liabilities:

.
Liabilities from commodity risk management activities:

Electricity derivatives $ —
$ (193 ) $ (151 ) $ (344 )
Natural gas derivatives —
(174 ) (19 ) (193 )
Heat rate derivatives —
—
(2 ) (2 )
Diesel fuel derivatives —
(5 ) —
(5 )
Coal derivatives —
(40 ) (1 ) (41 )
Total liabilities from commodity risk management activities —
(412 ) (173 ) (585 )
Liabilities from interest rate contracts —
(48 ) —
(48 )
Liabilities from outstanding common stock warrants (18 ) —
—
(18 )
Total liabilities $ (18 ) $ (460 ) $ (173 ) $ (651 )


	Fair Value as of December 31, 2014												Fair Value as of December 31, 2015
(amounts in millions)	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	88		$	22		$	110		$	—		$	308		$	40		$	348
Natural gas derivatives	—			3			—			3			—			40			2			42
Emissions derivatives	—			2			—			2
Coal derivatives													—			10			3			13
Total assets from commodity risk management activities	$	—		$	93		$	22		$	115		$	—		$	358		$	45		$	403
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(27	)	$	(26	)	$	(53	)	$	—		$	(267	)	$	(58	)	$	(325	)
Natural gas derivatives	—			(100		)	—			(100		)	—			(158		)	(34		)	(192		)
Diesel derivatives	—			(6		)	—			(6		)	—			(4		)	—			(4		)
Crude oil derivatives	—			(3		)	—			(3		)
Coal derivatives	—			(1		)	—			(1		)	—			(35		)	(1		)	(36		)
Total liabilities from commodity risk management activities	—			(137		)	(26		)	(163		)	—			(464		)	(93		)	(557		)
Liabilities from interest rate contracts	—			(44		)	—			(44		)	—			(42		)	—			(42		)
Liabilities from outstanding common stock warrants	(61		)	—			—			(61		)	(7		)	—			—			(7		)
Total liabilities	$	(61	)	$	(181	)	$	(26	)	$	(268	)	$	(7	)	$	(506	)	$	(93	)	$	(606	)

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts, ~~heat rate derivatives~~ and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. 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 correlation values. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps, and physical purchases executed in illiquid trading locations or on long dated contracts. The coal derivatives classified within Level 3 include financial swaps executed in illiquid trading locations.

Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices 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 of the spread on a buy or sell 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 ~~September 30, 2015~~March 31, 2016 are as follows:


Transaction Type	Quantity		Unit of Measure	Net Fair Value			Valuation Technique	Significant Unobservable Input	Significant Unobservable Inputs Range	Quantity		Unit of Measure	Net Fair Value			Valuation Technique	Significant Unobservable Input	Significant Unobservable Input Range
(dollars in millions)
Electricity derivatives:
Forward contracts—power (1)	(5	)	Million MWh	$	(40	)	Basis spread + liquid location	Basis spread	$7.00 - $9.00	(4	)	Million MWh	$	(12	)	Basis spread + liquid location	Basis spread	$5.00 - $7.00
FTRs	35		Million MWh	$	(9	)	Historical congestion	Forward price	$0.00 - $2.00	15		Million MWh	$	(5	)	Historical congestion	Forward price	$0 - $9.00
Heat rate derivatives:	—		Million MWh	$	3		Option model	Gas/power price correlation	70% - 100%
	2		Million MMBtu	$	(5	)	Option model	Power price volatility	14% - 34%
Natural gas derivatives (1)	39		Million MMBtu	$	(14	)	Illiquid location fixed price	Forward price	$1.61 - $1.97	75		Million MMBtu	$	(18	)	Illiquid location fixed price	Forward price	$1.20 - $1.50
Coal derivatives (1)	(50	)	Thousand Tons	$	3		Illiquid location fixed price	Forward price	$5.80 - $7.10	—		Thousand Tons	$	1		Illiquid location fixed price	Forward price	$4.20 - $5.10


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

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

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

Three Months Ended September 30, 2015
(amounts in millions)
Electricity
Derivatives
Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total
Balance at June 30, 2015 $ (54 ) $ (11 ) $ (7 ) $ 4
$ (68 )
Total gains (losses) included in earnings 2
(3 ) —
—
(1 )
Settlements (1) 3
—
5
(1 ) 7
Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3
$ (62 )
Unrealized gains (losses) relating to instruments held as of September 30, 2015 $ 2
$ (3 ) $ —
$ —
$ (1 )

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Nine Months Ended September 30, 2015
(amounts in millions)
Electricity
Derivatives
Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total
Balance at December 31, 2014 $ (4 ) $ —
$ —
$ —
$ (4 )
Acquisitions (54 ) (14 ) (9 ) 5
(72 )
Total gains included in earnings 7
—
—
—
7
Settlements (1) 2
—
7
(2 ) 7
Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3
$ (62 )
Unrealized gains relating to instruments held as of September 30, 2015 $ 7
$ —
$ —
$ —
$ 7



	Three Months Ended March 31, 2016
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Coal Derivatives			Total
Balance at December 31, 2015	$	(18	)	$	(32	)	$	2		$	(48	)
Total gains included in earnings	8			5			—			13
Settlements (1)	(7		)	9			(1		)	1
Balance at March 31, 2016	$	(17	)	$	(18	)	$	1		$	(34	)
Unrealized gains relating to instruments held as of March 31, 2016	$	8		$	5		$	—		$	13

Three Months Ended September 30, 2014
(amounts in millions)
Electricity
Derivatives
Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total
Balance at June 30, 2014 $ (14 ) $ —
$ (1 ) $ —
$ (15 )
Total gains (losses) included in earnings 3
(1 ) —
—
2
Settlements (1) (2 ) —
1
—
(1 )
Balance at September 30, 2014 $ (13 ) $ (1 ) $ —
$ —
$ (14 )
Unrealized gains (losses) relating to instruments held as of September 30, 2014 $ 3
$ (1 ) $ —
$ —
$ 2

Nine Months Ended September 30, 2014
(amounts in millions)
Electricity
Derivatives
Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total
Balance at December 31, 2013 $ 11
$ —
$ (1 ) $ —
$ 10
Total losses included in earnings (19 ) (1 ) —
—
(20 )
Settlements (1) (5 ) —
1
—
(4 )
Balance at September 30, 2014 $ (13 ) $ (1 ) $ —
$ —
$ (14 )
Unrealized losses relating to instruments held as of September 30, 2014 $ (19 ) $ (1 ) $ —
$ —
$ (20 )



	Three Months Ended March 31, 2015
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives		Coal Derivatives		Total
Balance at December 31, 2014	$	(4	)	$	—	$	—	$	(4	)
Total gains included in earnings	3			—		—		3
Settlements (1)	5			—		—		5
Balance at March 31, 2015	$	4		$	—	$	—	$	4
Unrealized gains relating to instruments held as of March 31, 2015	$	3		$	—	$	—	$	3


(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 in our 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 ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 and ~~2014.~~2015.

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 material nonfinancial assets or liabilities measured at fair value on a non-recurring basis during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ other than the provisional purchase price allocation discussed in Note 3—Acquisitions.

1817

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments recognized on our unaudited consolidated balance sheets. 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 ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015, respectively.


	September 30, 2015						December 31, 2014						March 31, 2016						December 31, 2015
(amounts in millions)	Carrying Amount			Fair Value			Carrying Amount			Fair Value			Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
6.75% Senior Notes, due 2019 ~~(6)~~(7)	$	(2,100	)	$	(2,116	)	$	(2,100	)	$	(2,132	)	$	(2,078	)	$	(2,090	)	$	(2,077	)	$	(1,985	)
Tranche B-2 Term Loan, due 2020 (1)(2)	$	(779	)	$	(780	)	$	(785	)	$	(775	)	$	(765	)	$	(766	)	$	(766	)	$	(754	)
7.375% Senior Notes, due 2022 ~~(6)~~(7)	$	(1,750	)	$	(1,768	)	$	(1,750	)	$	(1,777	)	$	(1,729	)	$	(1,628	)	$	(1,729	)	$	(1,531	)
5.875% Senior Notes, due 2023 ~~(2)~~(7)	$	(500	)	$	(469	)	$	(500	)	$	(475	)	$	(492	)	$	(423	)	$	(491	)	$	(404	)
7.625% Senior Notes, due 2024 ~~(6)~~(7)	$	(1,250	)	$	(1,259	)	$	(1,250	)	$	(1,272	)	$	(1,235	)	$	(1,131	)	$	(1,235	)	$	(1,078	)
Inventory financing agreements (2)	$	(127	)	$	(127	)	$	(23	)	$	(23	)
Equipment financing agreements (7)	$	(63	)	$	(63	)	$	—		$	—
Interest rate derivatives (2)	$	(48	)	$	(48	)	$	(44	)	$	(44	)
Commodity-based derivative contracts (3)	$	(162	)	$	(162	)	$	(48	)	$	(48	)
Common stock warrants (4)	$	(18	)	$	(18	)	$	(61	)	$	(61	)
Forward capacity agreement (3)(8)													$	(198	)	$	(198	)	$	—		$	—
Inventory financing agreements (8)													$	(134	)	$	(134	)	$	(136	)	$	(136	)
Equipment financing agreements (4)(8)													$	(62	)	$	(62	)	$	(61	)	$	(61	)
Interest rate derivatives (1)													$	(46	)	$	(46	)	$	(42	)	$	(42	)
Commodity-based derivative contracts (5)													$	(41	)	$	(41	)	$	(154	)	$	(154	)
Common stock warrants (6)													$	(6	)	$	(6	)	$	(7	)	$	(7	)
Genco:
7.00% Senior Notes Series H, due 2018 (2)(5)	$	(274	)	$	(275	)	$	(268	)	$	(264	)
6.30% Senior Notes Series I, due 2020 (2)(5)	$	(211	)	$	(209	)	$	(206	)	$	(208	)
7.95% Senior Notes Series F, due 2032 (2)(5)	$	(225	)	$	(235	)	$	(224	)	$	(241	)
7.00% Senior Notes Series H, due 2018 (1)(9)													$	(279	)	$	(120	)	$	(276	)	$	(204	)
6.30% Senior Notes Series I, due 2020 (1)(9)													$	(215	)	$	(85	)	$	(213	)	$	(148	)
7.95% Senior Notes Series F, due 2032 (1)(9)													$	(225	)	$	(88	)	$	(225	)	$	(162	)


(1)	~~Carrying amount includes an unamortized discount of $3 million as of~~ ~~September 30, 2015~~ ~~and December 31, 2014. Please read~~ ~~Note 13—Debt~~ ~~for further discussion.~~


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


(2)	Carrying amount includes an unamortized discount and debt issuance costs of $13 million and $14 million as of March 31, 2016 and December 31, 2015, respectively. Please read Note 12—Debt for further discussion.


(3)	Carrying amount includes an unamortized discount of $21 million as of March 31, 2016.


(4)	Carrying amounts for the equipment financing agreement include unamortized discounts of $14 million and $14 million as of March 31, 2016 and December 31, 2015, respectively.


(5)	Carrying amount of commodity-based derivative contracts excludes ~~$98~~$79 million and $9$106 million of cash posted as collateral, as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, respectively.


~~(4)~~(6)	The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels.


~~(5)~~(7)	Combined carrying amounts include debt issuance costs of $66 million and $68 million as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014 include unamortized discounts of $115 million and $127 million,~~2015, respectively. ~~Please read~~ ~~Note 13—Debt~~ ~~for further discussion.~~


~~(6)~~(8)	~~At December 31, 2014,~~The fair values of these debt agreements were held by Dynegy Finance I and Dynegy Finance II. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”).


~~(7)~~	~~Carrying amounts for the equipment financing agreement include unamortized discounts of $11 million as of September 30, 2015. In addition, the fair value is~~financial instruments are classified as Level 3 within the fair value hierarchy ~~levels.~~levels and are based on internal estimates.


(9)	Combined carrying amounts include unamortized discounts and debt issuance costs of $106 million and $111 million as of March 31, 2016 and December 31, 2015, respectively. Please read Note 12—Debt for further discussion.

1918

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Note 7—Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income, net of tax, by component isare as follows:


	Nine Months Ended September 30,						Three Months Ended March 31,
(amounts in millions)	2015			2014			2016			2015
Beginning of period	$	20		$	58		$	19		$	20
Other comprehensive loss before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax of $2 and zero, respectively)	7			(2		)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively) (1)	(3		)	(3		)	(1		)	(1		)
Net current period other comprehensive income (loss), net of tax	4			(5		)
Net current period other comprehensive loss, net of tax							(1		)	(1		)
End of period	$	24		$	53		$	18		$	19


(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 (gain). Please read Note ~~16—~~15—Pension and Other Post-Employment Benefit Plans for further discussion.

Note 8—Inventory

A summary of our inventories is as follows:


(amounts in millions)	September 30, 2015		December 31, 2014		March 31, 2016		December 31, 2015
Materials and supplies	$	177	$	83	$	176	$	175
Coal (1)	270		119		344		350
Fuel oil (1)	17		3		17		17
Emissions allowances (2)	64		2		39		51
Other	3		1		3		4
Total	$	531	$	208	$	579	$	597

(1)

At ~~September 30, 2015,~~March 31, 2016, approximately ~~$36~~$46 million and ~~$16~~$12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, ~~2014, there were no amounts that~~2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note ~~13—~~12—Debt—Brayton Point Inventory Financing for further discussion.


(2)	At ~~September 30,~~March 31, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. ~~At December 31, 2014, there were no amounts that were part of an inventory financing agreement.~~ Please read Note ~~13—~~12—Debt—Emissions Repurchase Agreements for further discussion.

Note 9—Property, Plant and Equipment

A summary of our property, plant and equipment is as follows:

(amounts in millions)
September 30, 2015
December 31, 2014
Power generation
$ 8,217

$ 3,174
Buildings and improvements
952

457
Office and other equipment
100

54
Property, plant and equipment
9,269

3,685
Accumulated depreciation
(784 )
(430 )
Property, plant and equipment, net
$ 8,485

$ 3,255

~~DYNEGY INC.~~



(amounts in millions)	March 31, 2016			December 31, 2015
Power generation	$	8,240		$	8,178
Buildings and improvements	958			956
Office and other equipment	103			101
Property, plant and equipment	9,301			9,235
Accumulated depreciation	(1,059		)	(888		)
Property, plant and equipment, net	$	8,242		$	8,347

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

On November 5, 2015, Dynegy announced that it expects to retire the final two units at its Wood River Power Station (“Wood River”) in mid-2016, subject to the approval of MISO. The decision to retire Wood River was the result of a strategic review performed in the third quarter, and was primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market that mixes out-of-state regulated generators, that receive rate based compensation from their home states to recover costs, with Central and Southern Illinois competitive generators that rely on the capacity market for fair compensation to recover costs. As a result of these factors, we performed an impairment analysis, which indicated that Wood River had a negative value. Therefore, we recorded an impairment charge of $74 million in Impairments and other charges in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015 to write off the entire carrying value. The fair value of Wood River was determined using a discounted cash flow model, assuming normal operations for the remainder of its estimated useful life. For the model, gross margin was based on publicly available forward market quotes, operations and maintenance expenses were based on current forecasts, and capital expenditures assumed the minimum of cash expenditures required to continue running the plant until its anticipated retirement. The valuation is classified as Level 3 within the fair value hierarchy levels.

Note 10—Joint Ownership of Generating Facilities

We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures,

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to ~~the~~ additional costs. Our share of revenues and operating costs of the jointly owned generating facilities are included within the corresponding financial statement line items in our unaudited consolidated statements of operations.

The following ~~table presents~~tables present the ownership interests of the jointly owned facilities as of March 31, 2016 and December 31, 2015 included in ~~the~~our unaudited consolidated balance ~~sheet.~~sheets. Each facility is co-owned with one or more other generation companies.

September 30, 2015
(dollars in millions)
Ownership Interest
Property, Plant and Equipment
Accumulated Depreciation
Construction Work in Progress
Total
Miami Fort (Units 7 and 8) (1)
64.0 %
$ 202

$ (11 )
$ 6

$ 197
J.M. Stuart (2)(3)
39.0 %
$ 32

$ (3 )
$ 12

$ 41
Conesville (Unit 4) (2)(3)
40.0 %
$ 61

$ (1 )
$ 3

$ 63
W.H. Zimmer (2)
46.5 %
$ 87

$ (7 )
$ 10

$ 90
Killen Station (1)(3)
33.0 %
$ 17

$ (1 )
$ 2

$ 18



	March 31, 2016
(dollars in millions)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Miami Fort	64.0	%	$	205	$	(22	)	$	3	$	186
Stuart (1)	39.0	%	$	32	$	(5	)	$	23	$	50
Conesville (1)	40.0	%	$	60	$	(1	)	$	4	$	63
Zimmer	46.5	%	$	99	$	(11	)	$	10	$	98
Killen (1)	33.0	%	$	17	$	(1	)	$	2	$	18



	December 31, 2015
(dollars in millions)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Miami Fort	64.0	%	$	207	$	(16	)	$	3	$	194
Stuart (1)	39.0	%	$	32	$	(4	)	$	20	$	48
Conesville (1)	40.0	%	$	61	$	(2	)	$	4	$	63
Zimmer	46.5	%	$	99	$	(10	)	$	11	$	100
Killen (1)	33.0	%	$	17	$	(1	)	$	2	$	18


(1)	~~Co-owned with The Dayton Power and Light Company.~~


~~(2)~~	~~Co-owned with The Dayton Power and Light Company and AEP Generation Resources Inc.~~


~~(3)~~	Facilities not operated by Dynegy.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Note 11—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014:~~2015:


	September 30, 2015									December 31, 2014									March 31, 2016									December 31, 2015
(amounts in millions)	Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount
Intangible Assets:
Electricity contracts	$	260		$	(100	)	$	160		$	111		$	(46	)	$	65		$	260		$	(148	)	$	112		$	260		$	(126	)	$	134
Coal contracts	—			—			—			—			—			—
Gas transport contracts	46			(4		)	42			—			—			—			46			(33		)	13			46			(16		)	30
Total intangible assets	$	306		$	(104	)	$	202		$	111		$	(46	)	$	65		$	306		$	(181	)	$	125		$	306		$	(142	)	$	164

Intangible Liabilities:
Electricity contracts	$	(30	)	$	15		$	(15	)	$	(20	)	$	14		$	(6	)	$	(30	)	$	25		$	(5	)	$	(30	)	$	19		$	(11	)
Coal contracts	(134		)	64			(70		)	(41		)	22			(19		)	(116		)	76			(40		)	(134		)	82			(52		)
Coal transport contracts	(104		)	56			(48		)	(81		)	32			(49		)	(104		)	71			(33		)	(104		)	64			(40		)
Gas transport contracts	(64		)	26			(38		)	(24		)	17			(7		)	(41		)	4			(37		)	(64		)	27			(37		)
Total intangible liabilities	$	(332	)	$	161		$	(171	)	$	(166	)	$	85		$	(81	)	$	(291	)	$	176		$	(115	)	$	(332	)	$	192		$	(140	)
Intangible assets and liabilities, net	$	(26	)	$	57		$	31		$	(55	)	$	39		$	(16	)	$	15		$	(5	)	$	10		$	(26	)	$	50		$	24

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 and ~~2014:~~2015:


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
(amounts in millions)	2015			2014			2015			2014			2016			2015
Electricity contracts, net (1)	$	21		$	16		$	53		$	77		$	16		$	7
Coal contracts, net (2)	(19		)	(3		)	(42		)	(11		)	(12		)	(3		)
Coal transport contracts, net (2)	(9		)	(8		)	(24		)	(22		)	(7		)	(6		)
Gas transport contracts, net (2)	(2		)	(2		)	(5		)	(6		)	17			(2		)
Total	$	(9	)	$	3		$	(18	)	$	38		$	14		$	(4	)


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


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

Note 12—Debt

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



(amounts in millions)	March 31, 2016			December 31, 2015
Dynegy Inc.:
6.75% Senior Notes, due 2019	$	2,100		$	2,100
Tranche B-2 Term Loan, due 2020	778			780
7.375% Senior Notes, due 2022	1,750			1,750
5.875% Senior Notes, due 2023	500			500
7.625% Senior Notes, due 2024	1,250			1,250
Forward Capacity Agreement	219			—
Inventory Financing Agreements	134			136
Equipment Financing Agreements	76			75
Genco:
7.00% Senior Notes Series H, due 2018	300			300
6.30% Senior Notes Series I, due 2020	250			250
7.95% Senior Notes Series F, due 2032	275			275
	7,632			7,416
Unamortized debt discounts and issuance costs (1)	(220		)	(207		)
	7,412			7,209
Less: Current maturities, including unamortized debt discounts and issuance costs, net	108			80
Total Long-term debt	$	7,304		$	7,129

(1) Includes $80 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion.

Senior Notes

As of March 31, 2016, we had $5.6 billion in senior notes that consisted of (i) $2.1 billion 6.75 percent senior notes, due 2019, (ii) $1.75 billion 7.375 percent senior notes, due 2022, (iii) $500 million 5.875 percent senior notes, due 2023, and (iv) $1.25 billion 7.625 percent senior notes, due 2024 (collectively, the “Senior Notes”).

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

~~The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the Acquisitions in April 2015:~~

EquiPower Acquisition Duke Midwest Acquisition
(amounts in millions/months) Gross Carrying Amount Weighted-Average Amortization Period Gross Carrying Amount Weighted-Average Amortization Period
Intangible Assets:
Electricity contracts $ 71
32
$ 80
38
Coal contracts —
—
—
9
Gas transport contracts 40
24
4
19
Total intangible assets $ 111
29
$ 84
37

Intangible Liabilities:
Electricity contracts $ —
—
$ (10 ) 23
Coal contracts (10 ) 21
(83 ) 27
Coal transport contracts (23 ) 22
—
—
Gas contracts —
1
—
—
Gas transport contracts (40 ) 128
—
—
Total intangible liabilities $ (73 ) 81
$ (93 ) 27
Total intangible assets and liabilities, net $ 38

$ (9 )

Amortization expense (revenue), net related to intangible assets and liabilities recorded in connection with the Acquisitions for the next five years as of September 30, 2015 is as follows: 2015—$8 million, 2016—$26 million, 2017—$19 million, 2018—$1 million and 2019—$(3) million.

~~Note 12—Asset Retirement Obligation~~

We record the present value of our legal obligations to retire tangible, long-lived assets on our balance sheets as liabilities when the liability is incurred. A summary of changes in our asset retirement obligations is as follows:

(amounts in millions) September 30, 2015
Balance, December 31, 2014 $ 224
Accretion expense 15
Liabilities settled in the current period (4 )
Acquisitions 105
Balance, September 30, 2015 $ 340

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~Note 13—Debt~~

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

(amounts in millions) September 30, 2015 December 31, 2014
Dynegy Inc.:
6.75% Senior Notes, due 2019 (1) $ 2,100
$ 2,100
Tranche B-2 Term Loan, due 2020 782
788
7.375% Senior Notes, due 2022 (1) 1,750
1,750
5.875% Senior Notes, due 2023 500
500
7.625% Senior Notes, due 2024 (1) 1,250
1,250
Revolving Facility —
—
Inventory Financing Agreements 127
23
Equipment Financing Agreements 74
—
Genco:
7.00% Senior Notes Series H, due 2018 300
300
6.30% Senior Notes Series I, due 2020 250
250
7.95% Senior Notes Series F, due 2032 275
275
7,408
7,236
Unamortized discounts on debt, net (129 ) (130 )
7,279
7,106
Less: Current maturities, including unamortized discounts, net 71
31
Total Long-term debt $ 7,208
$ 7,075


~~(1)~~	At December 31, 2014, these debt agreements were held by Dynegy Finance I and Dynegy Finance II. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”).

~~Debt Issuance~~

On October 27, 2014, Dynegy Finance II, Inc. (the “EquiPower Escrow Issuer”), a wholly-owned subsidiary of Dynegy, issued $3.06 billion in aggregate principal amount of senior notes, the proceeds of which were placed into escrow until the closing of the EquiPower Acquisition. On the EquiPower Closing Date, the proceeds from the issuance were released from escrow and used to pay a portion of the EquiPower Acquisition consideration and to pay fees and expenses. On the EquiPower Closing Date, Dynegy, as successor in interest to the EquiPower Escrow Issuer, executed supplemental indentures evidencing its accession to the 6.75 percent senior notes due 2019 (the “2019 Finance II Notes”), the 7.375 percent senior notes due 2022 (the “2022 Finance II Notes”), and the 7.625 percent senior notes due 2024 (the “2024 Finance II Notes” and, together with the 2019 Finance II Notes and the 2022 Finance II Notes, the “Finance II Notes”).

Further, on October 27, 2014, Dynegy Finance I, Inc. (the “Duke Escrow Issuer”), a wholly-owned subsidiary of Dynegy, issued $2.04 billion in aggregate principal amount of senior notes, the proceeds of which were placed into escrow until the closing of the Duke Midwest Acquisition. On the Duke Midwest Closing Date, the proceeds from the issuance were released from escrow and used to pay a portion of the Duke Midwest Acquisition consideration and to pay fees and expenses. On the Duke Midwest Closing Date, Dynegy, as successor in interest to the Duke Escrow Issuer, executed supplemental indentures evidencing its accession to the 6.75 percent senior notes due 2019 (the “2019 Finance I Notes”), the 7.375 percent senior notes due 2022 (the “2022 Finance I Notes”), and the 7.625 percent senior notes due 2024 (the “2024 Finance I Notes” and, together with the 2019 Finance I Notes and the 2022 Finance I Notes, the “Finance I Notes”). Concurrently with Dynegy’s accession to the Finance I Notes, as successor in interest to the Duke Escrow Issuer, each series of Finance I Notes was automatically exchanged for an equal aggregate principal amount of Finance II Notes with the same terms, as applicable, issued by Dynegy. The additional Finance II Notes issued pursuant to such automatic exchanges were treated as a single class for all purposes and are fully fungible with the Finance II Notes with the same terms previously issued under the Finance II indentures.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

On the EquiPower Closing Date, generally, each of Dynegy’s current wholly-owned domestic subsidiaries that is a borrower or guarantor under Dynegy’s existing credit facilities (the “Dynegy Guarantors”), and the entities acquired in the EquiPower Acquisition (the “EquiPower Guarantors”) executed supplemental indentures evidencing their accession to the Finance II Notes as guarantors. Similarly, on the Duke Midwest Closing Date, each of Dynegy’s current wholly-owned domestic subsidiaries that is a borrower or guarantor under Dynegy’s existing credit facilities and the entities acquired in the Duke Midwest Acquisition (the “Duke Guarantors” and, together with the Dynegy Guarantors and the EquiPower Guarantors, the “Guarantors”) executed supplemental indentures evidencing their accession to the Finance I Notes and the Finance II Notes as guarantors.

On the EquiPower Closing Date, the Dynegy Guarantors and the EquiPower Guarantors executed a joinder to the registration rights agreement, dated October 27, 2014, among the EquiPower Escrow Issuer, the Duke Escrow Issuer, and Morgan Stanley & Co. LLC, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and UBS Securities LLC as representatives of the initial purchasers identified therein (the “Registration Rights Agreement”). Additionally, on the Duke Midwest Closing Date, the Duke Guarantors executed a joinder to the Registration Rights Agreement.

As required by the Registration Rights Agreement, on July 17, 2015 Dynegy commenced registered exchange offers for the Notes, which closed on August 17, 2015. The terms of the exchange notes are identical in all material respects to the terms of the Notes, except that the exchange notes have been registered under the Securities Act. We received no proceeds from these exchange offers.

Credit Agreement

As of ~~September 30, 2015,~~March 31, 2016, we had a $2.225 billion credit agreement, as amended, that consisted of (i) an $800 million seven-year senior secured term loan B facility (the “Tranche B-2 Term Loan”) and (ii) a $1.425 billion ~~five-year~~in senior secured revolving credit ~~facility~~facilities (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). ~~Dynegy~~The Revolving Facility includes three incremental tranches of revolving commitments consisting of: (i) a $475 million tranche which will mature on April 23, 2018, (ii) a $350 million tranche which will mature April 1, 2020, and ~~its Subsidiary Guarantors (as defined in the Credit Agreement) also entered into an indenture pursuant to~~(iii) a $600 million tranche which ~~Dynegy issued $500 million in aggregate principal amount of unsecured senior notes (the “Senior Notes”) at par. Following the closings of the Acquisitions in~~will mature on April ~~2015, the acquired entities were added as additional subsidiary guarantors.~~2, 2020.

At ~~September 30, 2015,~~March 31, 2016, there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately ~~$430~~$441 million, which reduce 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 ~~were~~are in compliance ~~at September 30, 2015.~~

~~Credit Agreement Amendments.~~ ~~On the EquiPower Closing Date, Dynegy entered into a First Amendment to the Credit Agreement (the “First Amendment”) among Dynegy, certain subsidiaries~~as of Dynegy, the lenders party thereto, Credit Suisse AG, Cayman Islands Branch (“Credit Suisse”), as administrative agent, and the other parties thereto. The First Amendment provides for a new $350 million five-year senior secured incremental tranche of revolving commitments (the “Incremental Tranche A Revolving Loan Commitments”), which have terms substantially the same as the terms of the outstanding tranche of revolving loans under the Credit Agreement and will mature on April 1, 2020. Amounts available under the Incremental Tranche A Revolving Loan Commitments are available on a revolving basis, and such amounts that are repaid or prepaid may be re-borrowed. The loans issued pursuant to the Incremental Tranche A Revolving Loan Commitments bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate with respect to any Base Rate Loan, with steps down based on a Senior Secured Leverage Ratio (as such terms are defined in the Credit Agreement).

Further on the Duke Midwest Closing Date, Dynegy entered into a Second Amendment to the Credit Agreement (the “Second Amendment”) among the Company, certain subsidiaries of Dynegy, the lenders party thereto, Credit Suisse, as administrative agent, and the other parties thereto. The Second Amendment provides for a new $600 million five-year senior secured incremental tranche of revolving commitments (the “Incremental Tranche B Revolving Loan Commitments”), which have terms substantially the same as the terms of the outstanding tranche of revolving loans under the Credit Agreement and will mature on April 2, 2020. Amounts available under the Incremental Tranche B Revolving Loan Commitments are available on a revolving basis, and such amounts that are repaid or prepaid may be re-borrowed. The loans issued pursuant to the Incremental Tranche B Revolving Loan Commitments bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate with respect to any Base Rate Loan, with steps down based on a Senior Secured Leverage Ratio (as such terms are defined in the Credit Agreement).

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Subsequent to the First Amendment and Second Amendment, we have three tranches of revolvers: (i) $475 million tranche which will mature on April 23, 2018, (ii) $350 million tranche which will mature April 1, 2020 and (iii) $600 million tranche which will mature on April 2, 2020.March 31, 2016.

Genco Senior Notes

~~On December 2, 2013, in connection with the acquisition of New Ameren Energy Resources, LLC (“AER”),~~ Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) ~~remained outstanding as~~are an obligation of Genco, a subsidiary of IPH. The Genco Senior Notes are non-recourse to Dynegy.

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. 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.

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 external, 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 ~~September 30, 2015~~March 31, 2016 calculations, ~~Genco’s interest coverage ratios are less than~~Genco did not meet the ~~minimum~~ ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources.

Letter of Credit Facilities

On January 29, 2014, Illinois Power Marketing Company (“IPM”) entered into a fully cash collateralized LC and Reimbursement Agreement with an issuing bank, as amended on May 16, 2014 (“LC Agreement”), pursuant to which the issuing bank agreed to issue from time to time, one or more standby LCs 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 the issuing bank an amount of cash sufficient to cover the face value of such requested LC plus an additional percentage thereon. As of March 31, 2016, IPM had $14 million deposited with the issuing bank and $13 million in LCs outstanding.

On September 18, 2014, Dynegy entered into an LC Reimbursement Agreement with an issuing bank, and its affiliate (the “Lender”), for an LC in an amount not to exceed $55 million. The facility expires in September 2016. At March 31, 2016, there was $55 million outstanding under this LC.

On March 27, 2015, IPM entered into an LC facility with the Lender for up to $25 million. The facility, which is collateralized by Illinois Power Resources Generating, LLC (“IPRG”) receivables, has a two-year tenor and may be extended if

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

agreed to by both parties for one additional year. Interest on the facility is LIBOR plus 500 basis points on issued LCs. At March 31, 2016, there was $22 million outstanding under this LC facility.

Forward Capacity Agreement

On March 18, 2016, we entered into a bilateral contract with a financial institution to sell a portion of our forward cleared PJM capacity auction volumes. In exchange, we received $198 million in cash proceeds during the first quarter of 2016. The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2017-2018 and 2018-2019 in the amounts of $110 million and $109 million, respectively. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. The transaction is accounted for as a debt issuance of $219 million with an implied interest rate of 4.45 percent.

Inventory Financing Agreements

Brayton Point Inventory Financing. In connection with the EquiPower Acquisition, we assumed an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories at our Brayton Point facility, consisting of a debt obligation for existing and subsequent inventories, as well as a $15 million line of credit. Balances ~~on the line of credit~~ in excess of the $15 million line of credit are cash collateralized. ~~This~~The Inventory Financing Agreement terminates, and ~~our~~any remaining obligation becomes due and payable, on May 31, ~~2017, and is secured by a guaranty from Dynegy.~~2017. As of ~~September 30, 2015, our line~~March 31, 2016, there was $56 million outstanding under this agreement. Additionally, we had collateral postings of ~~credit balance was $23 million, of which~~ approximately ~~$8 million was collateralized by cash and included in Prepayments and other current assets on our unaudited consolidated balance sheets.~~$12 million.

As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation ~~cost,~~costs, and other expenses. The debt obligation increases for 85 percent of the total ~~price~~cost of the coal and for 90 percent ~~for~~of the total ~~price~~cost of the fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil costs, respectively. Upon consuming the materials, we repay the debt obligation and line of credit at the then market price, as defined within the Inventory Financing Agreement, for the amount of the materials consumed on a weekly basis.

~~The~~As of March 31, 2016, both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, ~~bears~~bear interest at an annual interest rate of the 3-month LIBOR plus 85.6 percent. An availability fee is calculated on a per annum rate of 0.75 ~~percent. As of September 30, 2015, the line of credit bears interest at 8.28~~ percent.

Emissions Repurchase Agreements. On August 14, 2015, we entered into a repurchase transaction with a third party in which we sold approximately $58 million of ~~Regional Greenhouse Gas Initiative (“RGGI”)~~RGGI inventory and received cash. We are obligated to repurchase a portion of the inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.56 percent. On August 20, 2015, we entered into an additional repurchase transaction with a third party in which we sold $20 million of RGGI inventory and received cash. We are obligated to repurchase the additional RGGI inventory in February 2017 at a specified price with an annualized carry cost of approximately 3.31 percent.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~In 2013, we entered into two repurchase transactions in which we sold $6~~ As of March 31, 2016, there was $78 million, in California Carbon Allowance (“CCA”) credits and $11 million of 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 $12 million of RGGI inventory and received cash. In October 2014, we repurchased all $6 million of the previously sold CCA credits and in February 2015, we repurchased all $23 million of the previously sold RGGI inventory.aggregate, outstanding under these agreements.

Equipment Financing Agreements

Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to ~~2025, and the~~2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our unaudited consolidated statements of cash flows. As of ~~September 30, 2015,~~March 31, 2016, there was ~~$74~~$76 million outstanding under these agreements. The related assets were recorded at the net present value of the payments of ~~$63~~$62 million. The ~~$11~~$14 million discount ~~will be~~is currently amortized as interest expense over the life of the payments.

~~Letter of Credit Facilities~~

On January 29, 2014, Illinois Power Marketing Company (“IPM”) entered into a fully cash collateralized Letter of Credit and Reimbursement Agreement with an issuing bank, as amended on May 16, 2014 (“LC Agreement”), pursuant to which the issuing 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 the issuing bank an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon. As of September 30, 2015, IPM had approximately $7 million deposited with the issuing bank and approximately $7 million in letters of credit outstanding.

On September 18, 2014, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, and its affiliate (the “Lender”), for a letter of credit in an amount not to exceed $55 million. The facility expires in May 2016. At September 30, 2015, there was $55 million outstanding under this letter of credit.

On March 27, 2015, IPM entered into a letter of credit facility with the Lender for up to $25 million. The facility, which is collateralized by receivables, has a two-year tenor and may be extended if agreed to by both parties for one additional year. Interest on the facility is LIBOR plus 500 basis points on issued letters of credit. At September 30, 2015, there was $20 million outstanding under this letter of credit facility.

Interest Rate Swaps

Subsequent to executing the Credit Agreement and issuing the Senior Notes, we amended our interest rate swaps to more closely match the terms of our Tranche B-2 Term Loan. The swaps have an aggregate notional value of approximately ~~$779~~$775 million at an average fixed rate of 3.19 percent with a floor of one percent, and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the new swaps are reflected as a financing activity in our unaudited consolidated ~~statement~~statements of cash flows.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

Note ~~14—~~13—Commitments and Contingencies

Legal Proceedings

Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, ~~and~~the nature of damages sought, and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments 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.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. 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 Dynegy Holdings, LLC debtor entities and their non-debtor affiliates in 2011 (the “2011 Prepetition Restructuring”), and specifically the transfer of Dynegy Midwest Generation, LLC (“DMG”), 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 transfer of DMG. 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 could 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 October 31, 2014, the Second Circuit affirmed the District Court’s dismissal based upon the lead plaintiff’s lack of standing. The lead plaintiff did not appeal to the U.S. Supreme Court.

Additionally, on July 19, 2013, the defendants filed a substantive motion to dismiss the plaintiff’s remaining claims by any opt-out plaintiffs against the non-debtor defendants. On April 30, 2014, the District Court granted the defendants’ motion and dismissed the action. On June 25, 2015, the Second Circuit Court affirmed the District Court’s dismissal and plaintiffs did not appeal to the U.S. Supreme Court.

Gas Index Pricing Litigation. We, ~~several of~~through our ~~affiliates, our former joint venture affiliate~~subsidiaries, and other energy companies ~~were~~are named as defendants in ~~numerous~~several lawsuits ~~in state and federal court~~ claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications infrom 2000-2002. The cases allege that 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,~~defendants engaged in an ~~illegal scheme~~antitrust conspiracy to inflate natural gas prices in ~~four~~three states ~~by providing false information to natural gas index publications.~~(Kansas, Missouri, and Wisconsin) during the relevant time period. The ~~remaining~~ cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. ~~In October 2015, the court issued a scheduling order including various discovery and pleading deadlines through 2016.~~ At this time we cannot reasonably estimate a potential loss.

Illinova Generating Company Arbitration. In May 2007, our subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million, which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award in the District Court of Dallas County, Texas. In March 2010, the Dallas District Court vacated the award, finding that one of the arbitrators had exhibited evident partiality. PPE appealed that decision to the Fifth District Court of Appeals in Dallas, Texas. Coincident with the appeal, IGC filed a claim against PPE seeking recovery of the $17 million plus interest. In September 2010, the Dallas District Court ordered PPE to deposit the $17 million principal in an interest-bearing escrow account jointly owned by IGC and PPE. On August 20, 2012, the Dallas Court of Appeals reversed the Dallas District Court and reinstated the award. ~~IGC and the other respondents filed a petition for review with the Texas Supreme Court on December 5, 2012.~~ On May 23, 2014, the Texas Supreme Court ~~reversed the Dallas Court of Appeals and reinstated the trial court’s judgment vacating~~vacated the arbitration ~~award. The Texas Supreme Court denied rehearing on August 22, 2014.~~award based upon the evident partiality of one of the arbitrators. On November 20, 2014, PPE initiated a new arbitration against IGC and its co-respondents, but the Dallas District Court enjoined the arbitration from proceeding against IGC while any dispute over ~~the escrow account~~IGC’s $17 million payment remains pending. On December 16, 2014, the Dallas District Court entered a judgment requiring ~~a full distribution~~the return of the ~~escrow account~~$17 million to IGC and an additional $2.5 million inpayment to IGC for interest. PPE paid the $17 million principal to IGC ~~from~~(not the ~~escrow account,~~$2.5 million in interest), but simultaneously appealed the ~~$17 million and $2.5 million interest~~ judgment, ~~in March 2015,~~ which remains ~~pending.~~pending in the Dallas Court of Appeals.

Other Contingencies

MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc.,

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. ~~Dynegy~~We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO ~~Tariff~~tariff in connection with the 2015-2016 PRA, ~~disputes~~disputed the allegations, and will defend ~~its~~our actions vigorously. ~~Dynegy filed its Answer to these complaints.~~ In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation.

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the arguments of the complainants regarding the 2015-2016 PRA, and stated that those issues remain under consideration and will be addressed in a future order.

New Source Review and CAA Matters.

New Source Review. 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 New Source Review and New Source Performance Standard 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.

In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006, and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting, and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 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 NOV.

Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. We plan to retire our Wood River facility on June 1, 2016, as approved by MISO.

CAA Notices of Violation. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we co-own but do not operate.

Edwards CAA Citizen Suit. 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 October 2016. We dispute the allegations and will defend the case vigorously.

Ultimate resolution of any of these CAA 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 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.

Stuart NPDES Permit Appeal. In January 2013, the Ohio EPA reissued the National Pollutant Discharge Elimination System (“NPDES”) permit for the co-owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. 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.

Coal Segment Groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.

At Baldwin, with approval of the Illinois EPA, we performed a comprehensive evaluation of the Baldwin Coal Combustion Residuals (“CCR”) surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the Illinois EPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. In April 2016, we submitted closure and post-closure care plans

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended March 31, 2016 and 2015

to the Illinois EPA for the Baldwin old east, east, and west fly ash CCR surface impoundments. We await Illinois EPA action on our plans.

We initiated an investigation at Baldwin in 2011 at the request of the Illinois EPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the Illinois EPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. Based on the data and groundwater flows, we do not believe that the exceedances are attributable to the Baldwin CCR surface impoundment system.

At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the Illinois EPA in 2012. Our hydrogeologic investigation indicates that these two CCR surface 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 recommend closure in place of both CCR surface impoundments and include an application to the Illinois EPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await Illinois EPA action on our proposed corrective action plans. In June 2015, we advised the Illinois EPA that the additional analyses requested by the Agency would be performed upon receipt of a riverbank stabilization permit from the U.S. Army Corps of Engineers. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million.

If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, 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 remediation, if any, that ultimately may be required.

IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill.

If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required.

Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of ~~coal combustion residual (“CCR”)~~CCR surface ~~impoundments.~~impoundments in 2009. 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 response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and 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, which is reflected in our ~~asset retirement obligation (“ARO”).~~AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the Illinois EPA in ~~August~~ 2014, and await Illinois EPA action.

In response to the Baldwin report, we notified the EPA in ~~April~~ 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent ~~ongoing~~ evaluation at Baldwin of groundwater corrective actions. InAt this time, to resolve the ~~first quarter 2015, we submitted to~~concerns raised in the ~~EPA engineering design information concerning repairs~~EPA’s assessment report and as a result of the ~~affected south berm at~~CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment and a deformation analysis of the Baldwin CCR surface impoundment’s north berm. The nature and scope of repairs that ultimately may be needed at the Baldwin CCR surface impoundment to address the EPA’s dam safety assessmentin 2017, which is dependent, in part, on the Illinois EPA’s response to our groundwater corrective action evaluation recommendations and our assessment of the federal EPA’s CCR rule. Please read “Vermilion and Baldwin Groundwater” below for further discussion. At this time, if the Illinois EPA approves our proposed approach to address groundwater at Baldwin and the EPA concurs, we estimate the cost to repair the affected berm at the Baldwin CCR surface impoundment would be approximately $3 million. If such approach is not approved by the Illinois EPA we are unable, at this time, to estimate a reasonably possible cost, or range of costs, of repairs at the Baldwin CCR surface impoundment.

~~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 New Source Review and New Source Performance Standard 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 CAA Section 114 Information Requests.~~ 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 (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~Wood River CAA Section 114 Information Request.~~ In May 2014, we received an information request from the EPA concerning our Coal segment’s Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any.

~~CAA Notices of Violation.~~ In December 2014, the EPA issued a NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate for the owners. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP and the station’s air permits involving standards applicable to opacity, SO2, sulfuric acid mist and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the co-owned Stuart and Killen facilities, which are operated by The Dayton Power and Light Company. 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 the NOV matters at the Zimmer, Stuart and Killen facilities.

~~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 July 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.

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

~~Stuart NPDES Permit Appeal.~~ In January 2013, the Ohio EPA issued a final National Pollutant Discharge Elimination System (“NPDES”) renewal permit for the co-owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the final permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. 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.

~~Vermilion and Baldwin Groundwater~~. In response to requests by the Illinois EPA, we have implemented hydrogeologic investigations for the CCR surface impoundment at our Baldwin facility and for two CCR surface impoundments at our Vermilion facility.

Groundwater monitoring results indicate that the CCR surface impoundment at Baldwin impacts onsite groundwater. Also, at the request of the Illinois EPA, in late 2011 we initiated an investigation at Baldwin 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. The cause of the exceedances is uncertain. If offsite groundwater impacts 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 (i.e., the old east CCR surface impoundment and the north CCR surface impoundment). The proposed corrective action plans reflect the results of a hydrogeologic investigation, which indicate that the facility’s old east and north CCR surface 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 surface 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. In March 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment at Vermilion. We await Illinois EPA action on our proposed corrective action plans. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million. The Vermilion facility also has a third CCR surface impoundment, the new east CCR surface 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 CCR surface impoundment by removing its CCR contents concurrent with the recommended closure alternative for the old east and north CCR surface impoundments, the associated estimated closure cost would add an additional $2 million to the above estimate.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

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 proposedreflected in our corrective action plans for the north and old east CCR surface impoundments is technically feasible. In September 2014, the Illinois EPA requested additional analyses concerning the closure plans for the Vermilion old east and north CCR surface impoundments. In June 2015, we advised the Illinois EPA that the additional analyses would be performed after receipt of a riverbank stabilization permit from the U.S. Army Corps of Engineers. In June 2014, we submitted the results of our evaluation at Baldwin to the Illinois EPA. Based on the results of that evaluation, we recommended to the Illinois EPA that the closure process for the Baldwin out-of-service east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the Baldwin out-of-service old east CCR surface impoundment be undertaken. In October 2014, we submitted a supplemental groundwater modeling report to the Illinois EPA that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. We await Illinois EPA action on our proposed corrective action plans and recommendations and continue to evaluate the impact of the federal EPA’s CCR rule. At this time we cannot reasonably estimate the costs of resolving these groundwater issues, 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.

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 addition, in April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill. In September 2015, we submitted an assessment monitoring report to the Illinois EPA concerning the Duck Creek facility’s active CCR landfill. The report concluded that there is no apparent release through the composite liner system of the landfill and that the previously reported groundwater quality standard exceedances appear to have resulted from stormwater discharges. We regraded the stormwater drainage system in January 2015 to prevent such discharges. The report also proposes establishment of a groundwater management zone.

In April 2013, Ameren Energy Resources Company filed a proposed site-specific rulemaking with the Illinois Pollution Control Board (“IPCB”) which, if approved, would provide for the systematic and eventual closure of our CCR surface impoundments that impact groundwater in exceedance of applicable groundwater standards. In October 2013, the Illinois EPA filed a proposed rulemaking with the IPCB that would establish processes governing monitoring, corrective action and closure of CCR surface impoundments at all power generating facilities in Illinois. The Illinois EPA’s proposed rulemaking has been stayed since May 2015 to consider the implications of the federal EPA’s CCR rule. The site-specific rulemaking proposal has also been stayed.

At this time, we cannot reasonably estimate the costs or range of costs of resolving the IPH groundwater 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. AROs.

Other Commitments

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 liquefied petroleum gas vessel charters. The following describes the more significant commitments outstanding at September 30, 2015.

~~Contractual Service Agreements.~~ Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. Recently we have undertaken several measures to restructure our existing maintenance agreements as

3126

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30, 2015 and 2014~~

well as negotiate new long-term maintenance service agreements with proven turbine service providers. The term of these 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 September 30, 2015, our minimum obligation with respect to these agreements is limited to the termination payments, which are approximately $357 million and $432 million in the event all contracts are terminated by us or the counterparty, respectively.

~~Coal Commitments.~~ During the nine months ended September 30, 2015, we entered into or assumed through our Acquisitions new long term contracts to purchase coal for our generation facilities with aggregate minimum commitments of $414 million. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

~~Coal Transportation.~~ During the nine months ended September 30, 2015, we executed or assumed through our Acquisitions new long term coal transportation contracts for our generation facilities with aggregate minimum commitments of $388 million.

~~Gas Transportation.~~ During the nine months ended September 30, 2015, we assumed through our Acquisitions firm capacity payment obligations related to transportation of natural gas. Such arrangements are routinely used in the physical movement and storage of energy. The total of such obligations was $141 million.

~~Charter Agreements.~~ 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 annually, through September 2016, at the option of the counterparty. The primary term of the second charter was through September 2014 but has been extended through September 2016 at the option of the counterparty. The first charter will terminate at the end of SeptemberMarch 31, 2016 and the second charter has an optional one-year extension remaining. 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 $4 million2015

transmission, transportation, storage and ~~$11 million~~leases for ~~the years ended December 31, 2015~~office space, equipment, design and ~~2016, respectively. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement~~construction, plant sites, and ~~has not exercised the remaining optional extension.~~power generation assets.

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.

~~LS Power Indemnities.~~In connection with the 2009 transaction with LS Power, we agreed to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities. Even though Dynegy was discharged from any claims pursuant to the order confirming the Plan, Dynegy Power Generation Inc., Dynegy Power, LLC (“DPC”), DMG and Dynegy Power Marketing, LLC remain jointly and severally liable for any indemnification claims. Although certain of the indemnification obligations are indefinite, some are no longer in effect under the relevant transaction agreements or have exceeded the 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. We have accrued no amounts with respect to the indemnifications as of ~~September 30, 2015~~March 31, 2016 because none were probable of occurring, nor could they be reasonably estimated.

~~EquiPower Acquisition.~~Delta Transaction Guarantees. In connection with the ECP Purchase Agreements, the ECP Purchasers agreed to indemnify the ECP Sellers against claims regarding breaches in the covenants and representations and warranties of the ECP Purchasers and certain other potential liabilities. The indemnification obligations of the ECP Purchasers survive for one year for most covenants and representations and warranties of the ECP Purchasers, two years for fundamental representations, and indefinitely for certain other matters. The ECP Sellers shall, in the aggregate, not be entitled to indemnification in excess of $276 million. We have

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~accrued no amounts with respect to this indemnification as of~~ ~~September 30, 2015. Please read Note 3—Acquisitions for further discussion.~~

~~Duke Midwest Acquisition.~~In connection with the Duke Midwest Purchase Agreement, Dynegy Resource I, LLC (“DRI”) agreed to indemnify Duke Energy against claims regarding breaches in the covenants and representations and warranties of DRI and certain other potential liabilities. The indemnification obligations of DRI survive for one year for most covenants and representations and warranties of DRI, three years for fundamental representations, 30 days after the applicable statute of limitations for certain tax matters, and indefinitely for certain other matters. We have accrued no amounts with respect to this indemnification as of ~~September 30, 2015~~. Dynegy has guaranteed, up to a maximum liability of $2.80 billion, the obligations of DRI under the Duke Midwest Purchase Agreement and related TSA. Please read Note 3—Acquisitions for further discussion.

~~Limited Guaranty.~~ ~~In connection with the acquisition of AER, Dynegy has provided a Limited Guaranty of certain obligations of IPH up to $25 million.~~ Concurrently with the execution of the ~~AER transaction agreement,~~Delta Transaction, each of Dynegy and one of the ECP Funds entered into ~~the Limited Guaranty, capped at $25 million~~limited guarantees in favor of ~~Ameren Corporation (“Ameren”), for a period~~GSENA to guarantee 65 percent and 35 percent, respectively, of ~~two years after~~ the ~~closing (subject~~Purchaser’s obligation to ~~certain exceptions)~~pay the reverse termination fee of $132 million in accordance with ~~respect to IPH’s indemnification obligations~~the terms and ~~certain reimbursement obligations under~~conditions of the ~~AER transaction agreement. We have accrued no amounts with respect to the guaranty as of~~ ~~September 30, 2015~~ ~~because none were probable of occurring, nor could they be reasonably estimated.~~Delta Transaction.

Note ~~15—~~14—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. Our Income tax expense for the three months ended March 31, 2016 includes a $15 million charge to deferred state income tax expense as a result of a change to our corporate tax structure in 2016.

As of ~~September 30, 2015,~~March 31, 2016, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future. For the three month period ending September 30, 2015, we have adjusted the fair value of the deferred tax liability acquired from EquiPower by $24 million resulting in the reduction of the previously recognized tax benefit for the release of the valuation allowance by $21 million. In addition we recorded a tax expense of $7 million for discreet items, including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance.

For the nine month period ending September 30, 2015, we have a tax benefit of $459 million for the release of our valuation allowance as a result of increased net deferred tax liabilities related to the EquiPower Acquisition. In addition we recorded a tax benefit of $14 million for discreet items, including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance. Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.

Note ~~16—~~15—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~~further described in Note ~~17—~~18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K. Upon the close of the Duke Midwest Acquisition on April 2, 2015, we assumed certain benefit plan obligations and the associated plan assets were transferred to us. As a result, we increased our net liability by approximately $13 million. These benefit plan obligations and related plan assets were merged into our pension and other post-employment benefit plans. The Duke employees began participating in our plans upon acquisition, which as a result triggered a re-measurement of our plans. As a result of the re-measurements, we recorded a loss through other comprehensive income and increased our net liability by approximately $5 million during the second quarter of 2015.

In August 2015, we finalized certain new collective bargaining agreements that resulted in amendments to certain pension and other post-employment benefit plans. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans using inputs as of July 31, 2015. We recorded a gain through other comprehensive income and decreased our net liability by approximately $15 million during the third quarter of 2015.

No benefit plan obligations associated with the EquiPower employees were assumed upon the EquiPower Acquisition on April 1, 2015. The EquiPower employees will become eligible to participate in our plans effective January 1, 2016.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Components of Net Periodic Benefit ~~Cost.~~Cost (Gain). The components of net periodic benefit cost (gain) were as follows:


	Pension Benefits						Other Benefits						Pension Benefits						Other Benefits
	Three Months Ended September 30,												Three Months Ended March 31,
(amounts in millions)	2015			2014			2015			2014			2016			2015			2016			2015
Service cost benefits earned during period	$	4		$	3		$	1		$	—		$	4		$	3		$	—		$	—
Interest cost on projected benefit obligation	4			4			1			1			5			4			1			1
Expected return on plan assets	(6		)	(5		)	(1		)	(1		)	(6		)	(5		)	(1		)	(1		)
Amortization of prior service credit	—			—			(1		)	(1		)	—			—			(1		)	(1		)
Net periodic benefit cost (gain)	$	2		$	2		$	—		$	(1	)	$	3		$	2		$	(1	)	$	(1	)

Pension Benefits Other Benefits
Nine Months Ended September 30,
(amounts in millions) 2015 2014 2015 2014
Service cost benefits earned during period $ 11
$ 9
$ 1
$ —
Interest cost on projected benefit obligation 13
13
3
3
Expected return on plan assets (17 ) (16 ) (3 ) (3 )
Amortization of prior service credit (1 ) (1 ) (2 ) (2 )
Net periodic benefit cost (gain) $ 6
$ 5
$ (1 ) $ (2 )

Note ~~17—~~16—Capital Stock

~~Share Repurchase Program~~

On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million initiated in the third quarter of 2015, with targeted completion in 2016. The shares have been and will continue to be purchased in the open market or privately negotiated transactions from time to time at management’s discretion at prevailing market prices. As of September 30, 2015, we had repurchased 4,996,299 shares at an aggregate cost of $127 million. From October 1 to October 13, 2015, we repurchased an additional 2,629,056 shares at an aggregate cost of $60 million.

Dividends

We pay quarterly dividends on our Mandatory Convertible Preferred Stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the ~~period from January 1, 2015 to September 30,~~three months ended March 31, 2016 and 2015, we paid an aggregate of ~~$17~~$5 million and $7 million in ~~dividends. We paid no~~ dividends ~~during 2014.~~on February 1, 2016 and February 2, 2015, respectively.

On ~~October 2, 2015,~~April 1, 2016, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the dividend period beginning on ~~August~~February 1, ~~2015~~2016 and ending on ~~October 31, 2015.~~April 30, 2016. Such dividends were paid on ~~November~~May 2, ~~2015~~2016 to stockholders of record as of ~~October~~April 15, ~~2015.~~2016.

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Note ~~18—Earnings (Loss)~~17—Loss Per Share

The ~~reconciliation of~~ basic ~~earnings (loss) per share to~~and diluted ~~earnings (loss)~~loss per share from continuing operations attributable to our common stockholders during the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ is shown in the following table. Please read Note ~~16—~~15—Capital Stock in our Form 10-K for further discussion.

Three Months Ended September 30, Nine Months Ended September 30,
(in millions, except per share amounts) 2015 2014 2015 2014
Income (loss) from continuing operations $ (24 ) $ (5 ) $ 181
$ (164 )
Less: Net income (loss) attributable to noncontrolling interest —
—
(3 ) 5
Income (loss) from continuing operations attributable to Dynegy Inc. (24 ) (5 ) 184
(169 )
Less: Dividends on preferred stock 5
—
16
—
Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic earnings (loss) per share (29 ) (5 ) 168
(169 )
Add: Dividends on preferred stock 5
—
16
—
Adjusted income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for diluted earnings (loss) per share $ (24 ) $ (5 ) $ 184
$ (169 )

Basic weighted-average shares 126
100
126
100
Effect of dilutive securities (1) —
—
14
—
Diluted weighted-average shares 126
100
140
100

Earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders:
Basic $ (0.23 ) $ (0.05 ) $ 1.33
$ (1.69 )
Diluted (1) $ (0.23 ) $ (0.05 ) $ 1.31
$ (1.69 )



	Three Months Ended March 31,
(in millions, except per share amounts)	2016			2015
Loss from continuing operations	$	(10	)	$	(181	)
Less: Net loss attributable to noncontrolling interest	—			(1		)
Loss from continuing operations attributable to Dynegy Inc.	(10		)	(180		)
Less: Dividends on preferred stock	5			5
Loss from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted loss per share	(15		)	(185		)

Basic and diluted weighted-average shares (1)	117			124

Basic and diluted loss per share from continuing operations attributable to Dynegy Inc. common stockholders (1)	$	(0.13	)	$	(1.49	)

(1)

Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have ~~utilized~~used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended ~~September 30, 2015~~March 31, 2016 and ~~the three and nine months ended September 30, 2014.~~2015.

For the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ 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 September 30,		Nine Months Ended September 30,		Three Months Ended March 31,
(in millions of shares)	2015	2014	2015	2014	2016	2015
Stock options	1.8	1.4	—	1.4	2.8	1.8
Restricted stock units	1.5	1.1	—	1.1	1.3	1.2
Performance stock units	0.6	0.3	—	0.3	1.2	0.6
Warrants	15.6	15.6	15.6	15.6	15.6	15.6
Series A 5.375% mandatory convertible preferred stock	12.9	—	—	—	12.9	12.9
Total	32.4	18.4	15.6	18.4	33.8	32.1

Note ~~19—~~18—Condensed Consolidating Financial Information

~~On May 20, 2013,~~ ~~Dynegy issued the Senior Notes, as further described in Note 13—Debt. On October 27, 2014, the Escrow Issuers, wholly-owned subsidiaries of Dynegy, issued the Notes as further described in~~ ~~Note 13—Debt~~. On the respective closing dates, Dynegy executed a second and third supplemental indenture adding the EquiPower Guarantors and the Duke Guarantors as guarantors of the $500 million in aggregate principal amount of the Senior Notes. The 100 percent owned subsidiary guarantors, jointly, severally, fully and unconditionally, guarantee the payment obligations under the Senior Notes and Notes. Not

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~all of Dynegy’s subsidiaries guarantee the Senior Notes and Notes including Dynegy’s indirect, wholly-owned subsidiary, IPH, which acquired AER and its subsidiaries on December 2, 2013.~~

The following condensed consolidating financial statements present the financial information of (i) Dynegy ~~(Parent)~~(“Parent”), which is the parent and issuer of the $5.6 billionSenior ~~Notes and~~ Notes, 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. The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee 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. Dynegy Finance I, Inc. and Dynegy Finance II, Inc (the “Escrow Issuers”) were merged with Parent effective April 2015. Please read Note 13—Debt in our Form 10-K for further discussion

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

For purposes of the unaudited condensed consolidating financial ~~information,~~statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014.~~2015.

~~Condensed Consolidating Balance Sheet as of September 30, 2015~~

~~(amounts in millions)~~

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Current Assets
Cash and cash equivalents $ 579
$ 176
$ 179
$ —
$ 934
Accounts receivable, net 503
1,397
169
(1,633 ) 436
Inventory —
316
215
—
531
Other current assets 26
287
66
(13 ) 366
Total Current Assets 1,108
2,176
629
(1,646 ) 2,267
Property, Plant and Equipment, Net —
7,875
610
—
8,485
Other Assets
Investment in affiliates 13,042
189
—
(13,042 ) 189
Goodwill —
818
—
—
818
Other assets 136
211
55
(4 ) 398
Intercompany note receivable 13
—
—
(13 ) —
Total Assets $ 14,299
$ 11,269
$ 1,294
$ (14,705 ) $ 12,157
Current Liabilities
Accounts payable $ 1,289
$ 228
$ 431
$ (1,633 ) $ 315
Other current liabilities 247
292
169
(13 ) 695
Total Current Liabilities 1,536
520
600
(1,646 ) 1,010
Debt, long-term portion 6,372
126
710
—
7,208
Intercompany note payable 3,042
—
13
(3,055 ) —
Other liabilities 168
396
198
(4 ) 758
Total Liabilities 11,118
1,042
1,521
(4,705 ) 8,976
Stockholders’ Equity
Dynegy Stockholders’ Equity 3,181
13,269
(226 ) (13,042 ) 3,182
Intercompany note receivable —
(3,042 ) —
3,042
—
Total Dynegy Stockholders’ Equity 3,181
10,227
(226 ) (10,000 ) 3,182
Noncontrolling interest —
—
(1 ) —
(1 )
Total Equity 3,181
10,227
(227 ) (10,000 ) 3,181
Total Liabilities and Equity $ 14,299
$ 11,269
$ 1,294
$ (14,705 ) $ 12,157

3628

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Condensed Consolidating Balance Sheet as of ~~December~~March 31, ~~2014~~2016

(amounts in millions)


	Parent		Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated		Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	1,642	$	—		$	54		$	174		$	—		$	1,870	$	639	$	80		$	102		$	—		$	821
Restricted cash	—		113			—			—			—			113		—		—			37			—			37
Accounts receivable, net	14		—			672			176			(592		)	270		539		1,329			115			(1,644		)	339
Inventory	—		—			88			120			—			208		—		309			270			—			579
Other current assets	9		6			125			73			—			213		14		454			47			(10		)	505
Total Current Assets	1,665		119			939			543			(592		)	2,674		1,192		2,172			571			(1,654		)	2,281
Property, Plant and Equipment, Net	—		—			2,812			443			—			3,255
Other Assets
Property, plant and equipment, net																	—		7,722			520			—			8,242
Investment in affiliates	6,133		—			—			—			(6,133		)	—		12,665		185			—			(12,665		)	185
Restricted cash	—		5,100			—			—			—			5,100
Goodwill																	—		797			—			—			797
Other assets	46		47			53			57			—			203		8		147			48			—			203
Intercompany note receivable	17		—			—			—			(17		)	—		17		—			—			(17		)	—
Total Assets	$	7,861	$	5,266		$	3,804		$	1,043		$	(6,742	)	$	11,232	$	13,882	$	11,023		$	1,139		$	(14,336	)	$	11,708
Current Liabilities
Accounts payable	$	310	$	166		$	112		$	220		$	(592	)	$	216	$	1,291	$	202		$	394		$	(1,644	)	$	243
Other current liabilities	51		67			250			97			—			465		193		291			146			(10		)	620
Total Current Liabilities	361		233			362			317			(592		)	681		1,484		493			540			(1,654		)	863
Debt, long-term portion	1,277		5,100			—			698			—			7,075		6,294		291			719			—			7,304
Intercompany note payable	3,042		—			—			17			(3,059		)	—		3,042		—			17			(3,059		)	—
Other liabilities	158		—			105			190			—			453		153		342			139			—			634
Total Liabilities	4,838		5,333			467			1,222			(3,651		)	8,209		10,973		1,126			1,415			(4,713		)	8,801
Stockholders’ Equity
Dynegy Stockholders’ Equity	3,023		(67		)	6,379			(179		)	(6,133		)	3,023		2,909		12,939			(274		)	(12,665		)	2,909
Intercompany note receivable	—		—			(3,042		)	—			3,042			—		—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	3,023		(67		)	3,337			(179		)	(3,091		)	3,023		2,909		9,897			(274		)	(9,623		)	2,909
Noncontrolling interest	—		—			—			—			—			—		—		—			(2		)	—			(2		)
Total Equity	3,023		(67		)	3,337			(179		)	(3,091		)	3,023		2,909		9,897			(276		)	(9,623		)	2,907
Total Liabilities and Equity	$	7,861	$	5,266		$	3,804		$	1,043		$	(6,742	)	$	11,232	$	13,882	$	11,023		$	1,139		$	(14,336	)	$	11,708

3729

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Condensed Consolidating ~~Statements~~Balance Sheet as of ~~Operations for the Three Months Ended September 30,~~December 31, 2015

(amounts in millions)

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Revenues $ —
$ 878
$ 249
$ 105
$ 1,232
Cost of sales, excluding depreciation expense —
(369 ) (147 ) (105 ) (621 )
Gross margin —
509
102
—
611
Operating and maintenance expense —
(154 ) (65 ) —

(219 )
Depreciation expense —
(149 ) (25 ) —
(174 )
Impairments and other charges —
(74 ) —
—
(74 )
General and administrative expense 3
(26 ) (6 ) —
(29 )
Acquisition and integration costs —
(8 ) —
—
(8 )
Operating income (loss) 3
98
6
—
107
Equity in earnings from investments in affiliates 53
—
—
(53 ) —
Losses from unconsolidated investments —
(4 ) —
—
(4 )
Interest expense (127 ) —
(18 ) —
(145 )
Other income and expense, net 47
(1 ) —
—
46
Income (loss) before income taxes (24 ) 93
(12 ) (53 ) 4
Income tax benefit (expense) —
(45 ) 17
—
(28 )
Net income (loss) (24 ) 48
5
(53 ) (24 )
Less: Net income attributable to noncontrolling interest —
—
—
—
—
Net income (loss) attributable to Dynegy Inc. $ (24 ) $ 48
$ 5
$ (53 ) $ (24 )



	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	327	$	94		$	84		$	—		$	505
Restricted cash	—		—			39			—			39
Accounts receivable, net	499		1,503			130			(1,730		)	402
Inventory	—		331			266			—			597
Other current assets	13		335			55			(14		)	389
Total Current Assets	839		2,263			574			(1,744		)	1,932
Property, plant and equipment, net	—		7,813			534			—			8,347
Investment in affiliates	13,017		190			—			(13,017		)	190
Other long-term assets	10		133			50			—			193
Goodwill	—		797			—			—			797
Intercompany note receivable	17		—			—			(17		)	—
Total Assets	$	13,883	$	11,196		$	1,158		$	(14,778	)	$	11,459
Current Liabilities
Accounts payable	$	1,388	$	238		$	396		$	(1,730	)	$	292
Other current liabilities	92		277			162			(14		)	517
Total Current Liabilities	1,480		515			558			(1,744		)	809
Long-term debt	6,293		122			714			—			7,129
Intercompany note payable	3,042		—			17			(3,059		)	—
Other long-term liabilities	147		317			138			—			602
Total Liabilities	10,962		954			1,427			(4,803		)	8,540
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,921		13,284			(267		)	(13,017		)	2,921
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,921		10,242			(267		)	(9,975		)	2,921
Noncontrolling interest	—		—			(2		)	—			(2		)
Total Equity	2,921		10,242			(269		)	(9,975		)	2,919
Total Liabilities and Equity	$	13,883	$	11,196		$	1,158		$	(14,778	)	$	11,459

~~Condensed Consolidating Statements of Operations for the Nine Months Ended September~~

30 ~~2015~~

~~(amounts in millions)~~

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Revenues $ —
$ 2,186
$ 672
$ (4 ) $ 2,854
Cost of sales, excluding depreciation expense —
(1,080 ) (418 ) 4
(1,494 )
Gross margin —
1,106

254

—

1,360
Operating and maintenance expense —
(385 ) (195 ) —

(580 )
Depreciation expense —
(352 ) (61 ) —
(413 )
Impairments and other charges —
(74 ) —
—
(74 )
Loss on sale of assets, net —
(1 ) —
—
(1 )
General and administrative expense —
(69 ) (25 ) —
(94 )
Acquisition and integration costs —
(121 ) —
—
(121 )
Operating income (loss) —
104

(27 )
—

77
Equity in earnings from investments in affiliates 500
—
—
(500 ) —
Losses from unconsolidated investments —
(1 ) —
—
(1 )
Interest expense (361 ) —
(52 ) —
(413 )
Other income and expense, net 45
—
—
—
45
Income (loss) before income taxes 184
103

(79 )
(500 )
(292 )
Income tax benefit (expense) —
473
—
—
473
Net income (loss) 184
576

(79 )
(500 )
181
Less: Net loss attributable to noncontrolling interest —
—
(3 ) —
(3 )
Net income (loss) attributable to Dynegy Inc. $ 184
$ 576

$ (76 )
$ (500 )
$ 184

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Condensed Consolidating Statements of Operations for the Three Months Ended ~~September 30, 2014~~March 31, 2016

(amounts in millions)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	379		$	236		$	—		$	615		$	—		$	887		$	236		$	—		$	1,123
Cost of sales, excluding depreciation expense	—			(229		)	(158		)	—			(387		)	—			(412		)	(133		)	—			(545		)
Gross margin	—			150			78			—			228			—			475			103			—			578
Operating and maintenance expense	—			(65		)	(49		)	—			(114		)	—			(159		)	(62		)	—			(221		)
Depreciation expense	—			(51		)	(10		)	—			(61		)	—			(146		)	(25		)	—			(171		)
Gain on sale of assets, net	—			3			—			—			3
General and administrative expense	(3		)	(13		)	(9		)	—			(25		)	(2		)	(28		)	(7		)	—			(37		)
Acquisition and integration costs	—			—			(9		)	—			(9		)	(3		)	(1		)	—			—			(4		)
Operating income (loss)	(3		)	24			1			—			22			(5		)	141			9			—			145
Earnings from unconsolidated investments																—			2			—			—			2
Equity in earnings from investments in affiliates	17			—			—			(17		)	—			118			—			—			(118		)	—
Interest expense	(18		)	(1		)	(14		)	1			(32		)	(124		)	(1		)	(17		)	—			(142		)
Other income and expense, net	5			—			1			(1		)	5			1			—			—			—			1
Income (loss) before income taxes	1			23			(12		)	(17		)	(5		)	(10		)	142			(8		)	(118		)	6
Income tax benefit (expense)	(6		)	—			6			—			—
Income tax expense																—			(16		)	—			—			(16		)
Net income (loss)	(5		)	23			(6		)	(17		)	(5		)	(10		)	126			(8		)	(118		)	(10		)
Less: Net income attributable to noncontrolling interest	—			—			—			—			—			—			—			—			—			—
Net income (loss) attributable to Dynegy Inc.	$	(5	)	$	23		$	(6	)	$	(17	)	$	(5	)	$	(10	)	$	126		$	(8	)	$	(118	)	$	(10	)

Condensed Consolidating Statements of Operations for the ~~Nine~~Three Months Ended ~~September 30, 2014~~March 31, 2015

(amounts in millions)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations		Consolidated
Revenues	$	—		$	1,279		$	619		$	—		$	1,898		$	—		$	—		$	413		$	219		$	—	$	632
Cost of sales, excluding depreciation expense	—			(857		)	(447		)	—			(1,304		)	—			—			(239		)	(138		)	—		(377		)
Gross margin	—			422			172			—			594			—			—			174			81			—		255
Operating and maintenance expense	—			(210		)	(150		)	—			(360		)	—			—			(60		)	(51		)	—		(111		)
Depreciation expense	—			(157		)	(28		)	—			(185		)	—			—			(56		)	(8		)	—		(64		)
Gain on sale of assets, net	—			17			—			—			17
General and administrative expense	(7		)	(42		)	(31		)	—			(80		)	(1		)	—			(17		)	(12		)	—		(30		)
Acquisition and integration costs	—			—			(17		)	—			(17		)	—			—			—			(90		)	—		(90		)
Operating income (loss)	(7		)	30			(54		)	—			(31		)	(1		)	—			41			(80		)	—		(40		)
Equity in losses from investments in affiliates	(60		)	—			—			60			—			(147		)	—			—			—			147		—
Earnings from unconsolidated investments	—			10			—			—			10
Interest expense	(62		)	(1		)	(42		)	1			(104		)	(27		)	(93		)	—			(16		)	—		(136		)
Other income and expense, net	(40		)	—			1			(1		)	(40		)	(5		)	—			—			—			—		(5		)
Income (loss) before income taxes	(169		)	39			(95		)	60			(165		)	(180		)	(93		)	41			(96		)	147		(181		)
Income tax benefit	—			—			1			—			1
Income tax expense																—			—			—			—			—		—
Net income (loss)	(169		)	39			(94		)	60			(164		)	(180		)	(93		)	41			(96		)	147		(181		)
Less: Net income attributable to noncontrolling interest	—			—			5			—			5
Less: Net loss attributable to noncontrolling interest																—			—			—			(1		)	—		(1		)
Net income (loss) attributable to Dynegy Inc.	$	(169	)	$	39		$	(99	)	$	60		$	(169	)	$	(180	)	$	(93	)	$	41		$	(95	)	$	147	$	(180	)

3931

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended ~~September 30, 2015~~March 31, 2016

(amounts in millions)


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated			Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(24	)	$	48	$	5	$	(53	)	$	(24	)	$	(10	)	$	126	$	(8	)	$	(118	)	$	(10	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain and plan amendments, net of tax of $2	6			—		7		—			13
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(1		)	—		—		—			(1		)	(1		)	—		—			—			(1		)
Other comprehensive income from investment in affiliates	7			—		—		(7		)	—
Other comprehensive income (loss), net of tax	12			—		7		(7		)	12
Other comprehensive loss, net of tax														(1		)	—		—			—			(1		)
Comprehensive income (loss)	(12		)	48		12		(60		)	(12		)	(11		)	126		(8		)	(118		)	(11		)
Less: Comprehensive income attributable to noncontrolling interest	1			—		1		(1		)	1
Less: Comprehensive loss attributable to noncontrolling interest														—			—		—			—			—
Total comprehensive income (loss) attributable to Dynegy Inc.	$	(13	)	$	48	$	11	$	(59	)	$	(13	)	$	(11	)	$	126	$	(8	)	$	(118	)	$	(11	)

Condensed Consolidating Statements of Comprehensive Income (Loss) for the ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2015

(amounts in millions)


	Parent			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations			Consolidated			Parent			Escrow Issuers			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	184		$	576	$	(79	)	$	(500	)	$	181		$	(180	)	$	(93	)	$	41	$	(96	)	$	147	$	(181	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $2	1			—		7			—			8
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(3		)	—		—			—			(3		)	(1		)	—			—		—			—		(1		)
Other comprehensive income from investment in affiliates	7			—		—			(7		)	—
Other comprehensive income (loss), net of tax	5			—		7			(7		)	5
Other comprehensive loss, net of tax															(1		)	—			—		—			—		(1		)
Comprehensive income (loss)	189			576		(72		)	(507		)	186			(181		)	(93		)	41		(96		)	147		(182		)
Less: Comprehensive loss attributable to noncontrolling interest	1			—		(2		)	(1		)	(2		)	—			—			—		(1		)	—		(1		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	188		$	576	$	(70	)	$	(506	)	$	188		$	(181	)	$	(93	)	$	41	$	(95	)	$	147	$	(181	)

4032

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

Condensed Consolidating Statements of ~~Comprehensive Income (Loss)~~Cash Flow for the Three Months Ended ~~September 30, 2014~~March 31, 2016

(amounts in millions)

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Net income (loss) $ (5 ) $ 23
$ (6 ) $ (17 ) $ (5 )
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) —
—
—
(1 )
Other comprehensive loss, net of tax (1 ) —
—
—
(1 )
Comprehensive income (loss) (6 ) 23
(6 ) (17 ) (6 )
Less: Comprehensive income attributable to noncontrolling interest —
—
—
—
—
Total comprehensive income (loss) attributable to Dynegy Inc. $ (6 ) $ 23
$ (6 ) $ (17 ) $ (6 )



	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(10	)	$	175		$	26		$	—		$	191
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(4		)	(50		)	(11		)	—			(65		)
Net intercompany transfers	339			—			—			(339		)	—
Distributions from unconsolidated affiliates	—			8			—			—			8
Net cash provided by (used in) investing activities	335			(42		)	(11		)	(339		)	(57		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowing on long term debt	—			198			—			—			198
Repayments of borrowings	(2		)	(3		)	—			—			(5		)
Dividends paid	(5		)	—			—			—			(5		)
Net intercompany transfers	—			(342		)	3			339			—
Interest rate swap settlement payments	(4		)	—			—			—			(4		)
Other financing	(2		)	—			—			—			(2		)
Net cash provided by (used in) financing activities	(13		)	(147		)	3			339			182
Net increase (decrease) in cash and cash equivalents	312			(14		)	18			—			316
Cash and cash equivalents, beginning of period	327			94			84			—			505
Cash and cash equivalents, end of period	$	639		$	80		$	102		$	—		$	821

Condensed Consolidating Statements of ~~Comprehensive Income (Loss)~~Cash Flow for the ~~Nine~~Three Months Ended ~~September 30, 2014~~March 31, 2015

(amounts in millions)

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
Net income (loss) $ (169 ) $ 39
$ (94 ) $ 60
$ (164 )
Other comprehensive income (loss) before reclassifications:
Actuarial loss, net of tax of zero —
—
(3 ) —
(3 )
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (3 ) —
—
—
(3 )
Other comprehensive income (loss) from investment in affiliates (3 ) —
—
3
—
Other comprehensive income (loss), net of tax (6 ) —
(3 ) 3
(6 )
Comprehensive income (loss) (175 ) 39
(97 ) 63
(170 )
Less: Comprehensive income (loss) attributable to noncontrolling interest (1 ) —
4
1
4
Total comprehensive income (loss) attributable to Dynegy Inc. $ (174 ) $ 39
$ (101 ) $ 62
$ (174 )



	Parent			Escrow Issuers			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	2		$	(94	)	$	46		$	(9	)	$	—		$	(55	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			—			(29		)	(11		)	—			(40		)
Net intercompany transfers	(188		)	—			—			—			188			—
Net cash provided by (used in) investing activities	(188		)	—			(29		)	(11		)	188			(40		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of borrowings	(2		)	—			(23		)	—			—			(25		)
Dividends paid	(7		)	—			—			—			—			(7		)
Net intercompany transfers	—			94			74			20			(188		)	—
Interest rate swap settlement payments	(4		)	—			—			—			—			(4		)
Other financing	(5		)	—			—			—			—			(5		)
Net cash provided by (used in) financing activities	(18		)	94			51			20			(188		)	(41		)
Net increase (decrease) in cash and cash equivalents	(204		)	—			68			—			—			(136		)
Cash and cash equivalents, beginning of period	1,642			—			54			174			—			1,870
Cash and cash equivalents, end of period	$	1,438		$	—		$	122		$	174		$	—		$	1,734

4133

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

~~Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 2015~~

~~(amounts in millions)~~

Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities $ (141 ) $ 502
$ (59 ) $ —
$ 302
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures (8 ) (122 ) (41 ) —
(171 )
Acquisitions, net of cash acquired

(6,207 ) 29
100
—
(6,078 )
Decrease in restricted cash 5,148
—
—
—
5,148
Net intercompany transfers 349
—
—
(349 ) —
Distributions from unconsolidated affiliates —
8
—
—
8
Other investing —
(6 ) —
—
(6 )
Net cash provided by (used in) investing activities (718 ) (91 ) 59
(349 ) (1,099 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings —
78
10
—
88
Repayments of borrowings (6 ) (23 ) —
—
(29 )
Financing costs from debt issuance (31 ) —
—
—
(31 )
Financing costs from equity issuance (6 ) —
—
—
(6 )
Dividends paid (17 ) —
—
—
(17 )
Net intercompany transfers —
(344 ) (5 ) 349
—
Interest rate swap settlement payments (13 ) —
—
—
(13 )
Repurchase of common stock (127 ) —
—
—
(127 )
Other financing (4 ) —
—
—
(4 )
Net cash provided by (used in) financing activities (204 ) (289 ) 5
349
(139 )
Net increase (decrease) in cash and cash equivalents (1,063 ) 122
5
—
(936 )
Cash and cash equivalents, beginning of period 1,642
54
174
—
1,870
Cash and cash equivalents, end of period $ 579
$ 176
$ 179
$ —
$ 934

~~Condensed Consolidating Statements of Cash Flow for the Nine Months Ended September 30, 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 $ (40 ) $ 315
$ 1
$ —
$ 276
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures —
(51 ) (43 ) —
(94 )
Proceeds from asset sales, net —
17
—
—
17
Net intercompany transfers 198
—
—
(198 ) —
Net cash provided by (used in) investing activities 198
(34 ) (43 ) (198 ) (77 )
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of financing costs (2 ) 12
—
—
10
Repayments of borrowings (6 ) —
—
—
(6 )
Net intercompany transfers —
(243 ) 45
198
—
Interest rate swap settlement payments (13 ) —
—
—
(13 )
Other financing (1 ) —
—
—
(1 )
Net cash provided by (used in) financing activities (22 ) (231 ) 45
198
(10 )
Net increase in cash and cash equivalents 136
50
3
—
189
Cash and cash equivalents, beginning of period 474
154
215
—
843
Cash and cash equivalents, end of period $ 610
$ 204
$ 218
$ —
$ 1,032

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Note ~~20—~~19—Segment Information

We report the results of our operations in three segments: (i) Coal, (ii) IPH, and (iii) Gas. The Coal segment includes certain of our coal-fired power generation facilities and our Dynegy Energy Services retail business. The IPH segment includes Genco, and ~~Illinois Power Resources Generating, LLC (“IPRG”),~~IPRG, which also own, directly and indirectly, certain of our coal-fired power generation facilities. IPH also includes 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. The Gas segment includes substantially all of our 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).

Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~ is presented below:

Segment Data as of and for the Three Months Ended ~~September 30, 2015~~March 31, 2016


(amounts in millions)	Coal			IPH			Gas			Other and Eliminations			Total			Coal			IPH			Gas			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	402		$	220		$	609		$	1		$	1,232		$	393		$	168		$	562		$	—		$	1,123
Intercompany revenues	(6		)	1			6			(1		)	—			(13		)	(1		)	14			—			—
Total revenues	$	396		$	221		$	615		$	—		$	1,232		$	380		$	167		$	576		$	—		$	1,123

Depreciation expense	$	(39	)	$	(8	)	$	(126	)	$	(1	)	$	(174	)	$	(39	)	$	(9	)	$	(122	)	$	(1	)	$	(171	)
General and administrative expense	—			—			—			(29		)	(29		)	—			—			—			(37		)	(37		)
Acquisition and integration costs	—			—			—			(8		)	(8		)	—			—			—			(4		)	(4		)

Operating income (loss)	$	(36	)	$	31		$	152		$	(40	)	$	107		$	54		$	14		$	120		$	(43	)	$	145

Losses from unconsolidated investments	—			—			(4		)	—			(4		)
Earnings from unconsolidated investments																—			—			2			—			2
Interest expense	—			—			—			(145		)	(145		)	(1		)	(17		)	(1		)	(123		)	(142		)
Other income and expense, net	—			—			—			46			46			—			—			—			1			1
Income before income taxes													4															6
Income tax expense	—			—			—			(28		)	(28		)	—			—			—			(16		)	(16		)
Net loss													(24		)													(10		)
Less: Net income attributable to noncontrolling interest													—
Less: Net loss attributable to noncontrolling interest																												—
Net loss attributable to Dynegy Inc.													$	(24	)													$	(10	)

Total assets—domestic	$	2,426		$	993		$	7,948		$	790		$	12,157		$	2,269		$	898		$	7,815		$	726		$	11,708
Investment in unconsolidated affiliate	$	—		$	—		$	189		$	—		$	189		$	—		$	—		$	185		$	—		$	185
Capital expenditures	$	(25	)	$	(12	)	$	(29	)	$	(3	)	$	(69	)	$	(19	)	$	(11	)	$	(31	)	$	(4	)	$	(65	)

4334

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

~~Segment Data as of and for the Nine Months Ended September 30, 2015~~

(amounts in millions) Coal IPH Gas
Other and
Eliminations
Total
Domestic:

Unaffiliated revenues $ 862
$ 625
$ 1,364
$ 3
$ 2,854
Intercompany revenues (17 ) —
20
(3 ) —
Total revenues $ 845
$ 625
$ 1,384
$ —
$ 2,854

Depreciation expense $ (96 ) $ (24 ) $ (290 ) $ (3 ) $ (413 )
General and administrative expense —
—
—
(94 ) (94 )
Acquisition and integration costs —
—
—
(121 ) (121 )

Operating income (loss) $ (34 ) $ 39
$ 290
$ (218 ) $ 77

Losses from unconsolidated investments —
—
(1 ) —
(1 )
Interest expense —
—
—
(413 ) (413 )
Other income and expense, net —
—
—
45
45
Loss before income taxes

(292 )
Income tax benefit —
—
—
473
473
Net income 181
Less: Net loss attributable to noncontrolling interest (3 )
Net income attributable to Dynegy Inc. $ 184

Total assets—domestic

$ 2,426
$ 993
$ 7,948
$ 790
$ 12,157
Investment in unconsolidated affiliate $ —
$ —
$ 189
$ —
$ 189
Capital expenditures $ (44 ) $ (41 ) $ (78 ) $ (8 ) $ (171 )

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

Segment Data as of and for the Three Months Ended ~~September 30, 2014~~March 31, 2015


(amounts in millions)	Coal			IPH			Gas			Other and Eliminations			Total			Coal			IPH			Gas			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	132		$	237		$	246		$	—		$	615		$	154		$	219		$	259		$	—		$	632
Intercompany revenues	5			(1		)	(4		)	—			—			(12		)	—			12			—			—
Total revenues	$	137		$	236		$	242		$	—		$	615		$	142		$	219		$	271		$	—		$	632

Depreciation expense	$	(14	)	$	(10	)	$	(36	)	$	(1	)	$	(61	)	$	(10	)	$	(8	)	$	(45	)	$	(1	)	$	(64	)
Gain on sale of assets, net	—			—			3			—			3
General and administrative expense	—			—			—			(25		)	(25		)	—			—			—			(30		)	(30		)

Operating income (loss)	$	(2	)	$	19		$	40		$	(35	)	$	22		$	7		$	22		$	52		$	(121	)	$	(40	)

Earnings from unconsolidated investments	—			—			—			—			—
Interest expense	—			—			—			(32		)	(32		)	—			—			—			(136		)	(136		)
Other income and expense, net	—			1			—			4			5			—			—			—			(5		)	(5		)
Loss before income taxes													(5		)													(181		)
Income tax benefit	—			—			—			—			—
Income tax expense																—			—			—			—			—
Net loss													(5		)													(181		)
Less: Net income attributable to noncontrolling interest													—
Less: Net loss attributable to noncontrolling interest																												(1		)
Net loss attributable to Dynegy Inc.													$	(5	)													$	(180	)

Total assets—domestic	$	1,100		$	1,021		$	2,189		$	737		$	5,047		$	1,162		$	1,037		$	2,105		$	6,827		$	11,131
Capital expenditures	$	(10	)	$	(12	)	$	(2	)	$	(1	)	$	(25	)	$	(3	)	$	(11	)	$	(24	)	$	(2	)	$	(40	)

Note 20—Subsequent Event

On May 3, 2016, Dynegy announced the shutdown of two of the three units at its Baldwin power generation facility in Baldwin, Illinois and one of the two units at its Newton power generation facility in Newton, Illinois. Subject to the approval of MISO, we expect to shut down the units over the next year. This decision was made after the units failed to recover their basic operating costs in the most recent MISO auction. Factors influencing these actions included a low power pricing environment, a lack of capacity revenue, and significant maintenance and environmental expenditures required to appropriately maintain the facilities. We will assess the carrying value of our entire MISO fleet for impairment during the second quarter of 2016. As of March 31, 2016, our MISO facilities had a combined carrying value of $1.4 billion.

4535

~~DYNEGY INC.~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS~~

~~(Unaudited)~~

~~For the Interim Periods Ended September 30, 2015 and 2014~~

~~Segment Data as of and for the Nine Months Ended September 30, 2014~~

(amounts in millions) Coal IPH Gas
Other and
Eliminations
Total
Domestic:

Unaffiliated revenues $ 429
$ 618
$ 851
$ —
$ 1,898
Intercompany revenues —
1
(1 ) —
—
Total revenues $ 429
$ 619
$ 850
$ —
$ 1,898

Depreciation expense $ (39 ) $ (28 ) $ (115 ) $ (3 ) $ (185 )
Gain on sale of assets, net —
—
17
—
17
General and administrative expense —
—
—
(80 ) (80 )

Operating income (loss) $ 2
$ (14 ) $ 72
$ (91 ) $ (31 )

Earnings from unconsolidated investments —
—
10
—
10
Interest expense —
—
—
(104 ) (104 )
Other income and expense, net —
1
—
(41 ) (40 )
Loss before income taxes

(165 )
Income tax benefit —
—
—
1
1
Net loss (164 )
Less: Net income attributable to noncontrolling interest 5
Net loss attributable to Dynegy Inc. $ (169 )

Total assets—domestic

$ 1,100
$ 1,021
$ 2,189
$ 737
$ 5,047
Capital expenditures $ (21 ) $ (43 ) $ (27 ) $ (3 ) $ (94 )

DYNEGY INC.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION

AND RESULTS OF OPERATIONS

For the Interim Periods Ended ~~September 30,~~March 31, 2016 and 2015 ~~and 2014~~

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 ~~unregulated~~ power generation sector of the energy industry. We currently own approximately 26,000 MW of generating capacity in eight states and also provide retail electricity to 1,034,000 residential customers and 38,000 commercial, industrial, and municipal customers in Illinois, Ohio, and Pennsylvania. 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”).

On February 24, 2016, through Atlas Power, we signed the Delta Stock Purchase Agreement to acquire GSENA (Engie S.A’s United States merchant fossil portfolio) consisting of approximately 8,700 MWs of generation capacity located in ERCOT, PJM, and ISO-NE. The JV has financing commitments for the $3.3 billion acquisition, as well as related transaction fees and working capital, with $2.25 billion in committed debt facilities and $1.185 billion in equity commitments by us and ECP Funds. We expect the transaction to close in the fourth quarter of 2016 after satisfaction or waiver of customary closing conditions, including approval from FERC, the Public Utility Commission of Texas, and expiration of Hart-Scott-Rodino waiting period, which occurred on April 1, ~~2015,~~2016. Please read Note 3—Acquisitions for further discussion of the Delta Transaction and related agreements.

On March 18, 2016, we completed the acquisition of EquiPower Resources Corp. and Brayton Point Holdings, LLC from Energy Capital Partners for an aggregate base purchase price of approximately $3.35 billion in cash plus $105 million in common stock of Dynegy (the “EquiPower Acquisition”), subjectentered into a bilateral contract to certain adjustments. On April 2, 2015, we completed the acquisition of Duke Energy’s commercial generation assets and retail business in the Midwest for a base purchase price of approximately $2.80 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments. With these transactions, we now own approximately 26,000sell 2,300 MW of ~~generating~~cleared PJM capacity ~~in eight states~~(1,500 MW of Base Capacity and ~~also provide retail electricity to 895,000 residential customers and 30,200 commercial, industrial and municipal customers in Illinois, Ohio and Pennsylvania.~~

~~On August 3, 2015, our Board~~800 MW of Directors authorized a share repurchase program for up to $250 million, initiated in the third quarter of 2015, with targeted completion in 2016. The shares will be purchased in the open market or privately negotiated transactions from time to time at management’s discretion at prevailing market prices. As of September 30, 2015, we had repurchased 4,996,299 shares at an aggregate cost of $127 million. From October 1 to October 13, 2015, we repurchased an additional 2,629,056 shares at an aggregate cost of $60 million.

~~In August and September of 2015, PJM conducted its capacity auctions for its new~~ Capacity Performance (“CP”) ~~product.~~Product) in Planning Year 2017-2018 and 1,900 MW of cleared PJM capacity (1,000 MW of Base Capacity and 900 MW of CP Product) in Planning Year 2018-2019. In exchange, we received $198 million in cash proceeds in the first quarter of 2016. The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2017-2018 and 2018-2019 in the amounts of $110 million and $109 million, respectively. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. Please read ~~Outlook~~Note 12—Debt for further discussion.

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, 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 our revolving and letter of credit (“LC”) facilities.

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 Illinois Power Generating Company (“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. Genco’s $825 million Senior Notes are non-recourse to Dynegy.

~~In connection with the closings~~As a result of ~~the Acquisitions,~~continued weak energy prices, unsold capacity volumes, on-going required maintenance and environmental expenditures, as well as consideration of a $300 million debt maturity in 2018; we ~~entered into amendments to the Credit Agreement which provide for incremental revolving credit facilities that expand the credit available to us by an aggregate~~will begin a strategic review of $950 million which will be used to support our collateral and liquidity requirements. The loans issued pursuant to these facilities bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate withIPH’s Genco

4736

Table of Contents

~~respect~~subsidiary immediately. We intend to ~~any Base Rate Loan, with steps down based on~~resolve this situation by either restructuring the Genco debt to achieve a ~~Senior Secured Leverage Ratio. Subsequent~~more sustainable business model or transitioning ownership to the ~~delivery of our September 30, 2015~~ debt ratio calculations, we anticipate that we will be able to lower the interest rate margin on our Revolving Facility from 2.75 percent to 2.25 percent per annum and the commitment fees on the unutilized portion of the facility from 0.5 percent to 0.375 percent.

On March 27, 2015, IPM entered into a letter of credit facility with an issuing bank for up to $25 million. The facility, which is collateralized by receivables, has a two-year tenor and may be extended if agreed to by both parties for one additional year. Interest on the facility is LIBOR plus 500 basis points on issued letters of credit. At September 30, 2015, there was approximately $20 million outstanding under this letter of credit facility.holders. Please read Note ~~13—Debt—Letter of Credit Facilities~~12—Debt for further discussion.

Liquidity. The following table summarizes our liquidity position at ~~September 30, 2015:~~March 31, 2016:


	September 30, 2015									March 31, 2016
(amounts in millions)	Dynegy Inc.			IPH (1) (2)			Total			Dynegy Inc.			IPH (1) (2)			Total
Revolving facilities and LC capacity (3)	$	1,480		$	25		$	1,505		$	1,480		$	39		$	1,519
Less: Outstanding letters of credit	(485		)	(20		)	(505		)
Less: Outstanding LCs										(496		)	(35		)	(531		)
Revolving facilities and LC availability	995			5			1,000			984			4			988
Cash and cash equivalents	789			145			934			743			78			821
Total available liquidity (4)	$	1,784		$	150		$	1,934		$	1,727		$	82		$	1,809


(1)	Includes Cash and cash equivalents of ~~$128~~$55 million related to Genco.


(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)

~~Includes:~~Dynegy includes: (i) $950 million of aggregate available capacity related to our incremental revolving credit facilities,(ii) $475 million of available capacity related to the five-year senior secured revolving credit facility, and (iii) $55 million related to an LC. IPH includes (i) up to a ~~letter~~maximum of ~~credit and (ii)~~ $25 million related to the two-year secured ~~letter of credit facility.~~LC facility and (ii) $14 million related to our fully cash collateralized LC and reimbursement agreement. Please read Note ~~13—~~12—Debt—Letter of Credit Facilities for further discussion.


(4)	On December 2, 2013, Dynegy and Illinois Power Resources, LLC entered into an intercompany revolving promissory note of $25 million. At ~~September 30, 2015,~~March 31, 2016, there was approximately ~~$16~~$25 million outstanding on the note, which is not reflected in the table above.

In conjunction with the JV’s $1.85 billion committed senior secured debt financing arrangements for the Delta Transaction, we have secured an incremental revolver commitment in the amount of $100 million at Dynegy Inc., and the JV has secured an incremental revolver commitment in the amount of $25 million at Atlas Power, for liquidity needs.

The following table presents net cash from operating, investing, and financing activities for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 and ~~2014:~~2015:


	Nine Months Ended September 30,						Three Months Ended March 31,
(amounts in millions)	2015			2014			2016			2015
Net cash provided by operating activities	$	302		$	276
Net cash provided by (used in) operating activities							$	191		$	(55	)
Net cash used in investing activities	$	(1,099	)	$	(77	)	$	(57	)	$	(40	)
Net cash used in financing activities	$	(139	)	$	(10	)
Net cash provided by (used in) financing activities							$	182		$	(41	)

Operating Activities

Historical Operating Cash Flows. Cash provided by operations totaled ~~$302~~$191 million for the ~~nine~~three months ended ~~September 30, 2015.~~March 31, 2016. During the period, our power generation business provided cash of ~~$655~~$259 million primarily due to the operation of our power generation facilities and ~~our~~ retail operations. Corporate and other activities used cash of ~~$357~~$19 million primarily due to interest payments on our various debt ~~agreements~~agreements. Changes in working capital and other, including general and administrative expenses, used cash of ~~$263~~$49 million, net, during the period.

Cash used in operations totaled $55 million for the three months ended March 31, 2015. During the period, our power generation business provided cash of $111 million primarily due to the operation of our power generation facilities and retail operations. Corporate and other activities used cash of $99 million primarily due to interest payments on the Senior Notes issued in 2014 of $92 million funded into the escrow account related to those Senior Notes, interest payments related to our Credit Agreement, Senior Notes and Genco Senior Notes of $16 million, and payments for acquisition-related costs of ~~$111~~$8 million, offset by $17 million related to the Ponderosa Pine Energy, LLC cash receipt. ~~Changes~~In addition, changes in working capital and other, including general and administrative expenses, ~~provided cash of $4 million, net, during the period.~~

Cash provided by operations totaled $276 million for the nine months ended September 30, 2014. During the period, our power generation business provided cash of $285 million primarily due to the operation of our power generation facilities and our retail operations. Corporate and other activities used cash of approximately ~~$97 million primarily due to interest payments on our various debt agreements of $73 million and payments for acquisition-related costs of $24~~$67 million. ~~In addition, we had $88 million in positive working capital and other changes.~~

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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 our ~~PRIDE~~“PRIDE Energized” initiative.

Collateral Postings. We use a portion of our capital resources in the form of cash and ~~letters of credit~~LCs to satisfy counterparty collateral demands. The following table summarizes our collateral postings to third parties at ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014:~~2015:


(amounts in millions)	September 30, 2015		December 31, 2014		March 31, 2016		December 31, 2015
Dynegy Inc.:
Cash (1)	$	144	$	14	$	147	$	159
Letters of credit	485		178
LCs					496		475
Total Dynegy Inc.	629		192		643		634

IPH:
Cash (1) (2)	3		32		17		11
Letters of credit (3)	27		10
LCs (3) (4)					35		45
Total IPH	30		42		52		56

Total	$	659	$	234	$	695	$	690

(1)

Includes broker margin as well as other collateral postings included in Prepayments and other current assets on our unaudited consolidated balance sheets. At ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014, $98~~2015, $79 million and $9$106 million, respectively, of cash ~~respectively,~~ posted as collateral were netted against Liabilities from risk management activities on our unaudited consolidated balance sheets.


(2)	Includes cash of approximately $1$7 million and $5$1 million ~~respectively,~~ related to Genco at ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014.~~2015, respectively.


(3)	Includes ~~letters of credit~~LCs of approximately $7$13 million and ~~$10~~$20 million outstanding as of March 31, 2016 and December 31, 2015, respectively, related to the cash-backed LC facility at Illinois Power Marketing Company (“IPM”). Please read Note 12—Debt—Letter of Credit Facilities for further discussion.


(4)	Includes LCs of approximately $22 million related to the ~~$25 million cash-backed~~two-year secured LC ~~facility at~~entered into by IPM ~~at September 30, 2015~~ and ~~December 31, 2014, respectively.~~collateralized by IPRG receivables.

~~In addition~~Collateral postings decreased from December 31, 2015 to ~~cash and letters~~March 31, 2016 primarily due to reduced collateral requirements of ~~credit~~hedging activity. LCs posted as collateral ~~we have~~ increased the number of counterparties that participate in our first priority lien program. 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.

~~Collateral postings increased from December 31, 2014 to September 30, 2015~~ primarily due to ~~acquisition-related collateral requirements and other changes in our commercial activity.~~

increased postings to various ISOs for annual transmission production auctions. The fair value of our derivatives collateralized by first priority liens included liabilities of ~~$191~~$146 million and ~~$141~~$167 million at ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014,~~2015, 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 economic hedging instruments in the future could be limited due to the potential collateral requirements of such instruments.

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Investing Activities

~~Capital Expenditures.~~Historical Investing Cash Flows. During the three months ended March 31, 2016, we paid $65 million in capital expenditures and received an $8 million cash inflow related to distributions from our unconsolidated investment in Elwood. Our capital spending by reportable segment was as follows:


	Nine Months Ended September 30,				Three Months Ended March 31,
(amounts in millions)	2015		2014		2016		2015
Coal	$	44	$	21	$	19	$	3
IPH	41		43		11		11
Gas	78		27		31		24
Other	8		3		4		2
Total (1)	$	171	$	94	$	65	$	40


(1)	Includes capitalized interest of $9$4 million and ~~$15~~$3 million for the ~~nine~~three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively.

Future Investing Cash Flows. We expect capital expenditures for the remainder of 2016 to be approximately $254 million, which is comprised of $49 million, $18 million, $183 million, and $4 million in Coal, IPH, Gas, and Other, ~~Investing Activities.~~ ~~During the nine months ended September 30, 2015, we paid $6.078 billion in~~respectively. The capital budget is subject to revision as opportunities arise or circumstances change. Additionally, our future investing cash ~~net of cash acquired, in connection with the Acquisitions. In addition, there was a $5.148 billion cash inflow related~~flows will be reduced by funds used to ~~the release of restricted cash as a result of closing the Acquisitions. Please read Note 11—Debt in our Form 10-K and Note 3—Acquisitions for further discussion.~~fund Atlas Power.

During the nine months ended September 30, 2014, there was a $17 million cash inflow related to cash proceeds received upon the close of the sale of our 50 percent partnership interest in Nevada Cogeneration Associates #2, a partnership that owns Black Mountain. Please read Note 22—Dispositions and Discontinued Operations in our Form 10-K for further discussion.

Financing Activities

Historical Financing Cash ~~Flow from Financing Activities.~~Flows. Cash ~~used in~~provided by financing activities totaled ~~$139~~$182 million for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 primarily due to ~~(i) $127~~$198 million of ~~payments~~proceeds related to our ~~share repurchase program, (ii) $37 million in financing costs related to our debt and equity issuances, (iii) $29~~forward capacity agreement, offset by (i) $5 million in repayments associated with our inventory financing agreements and term loan, ~~(iv) $17~~(ii) $5 million in dividend payments on our Mandatory Convertible Preferred Stock, and ~~(v) $13~~(iii) $4 million in interest rate swap settlement ~~payments, offset by $88 million in proceeds received related to inventory financing agreements.~~payments. Please read Note ~~13—~~12—Debt and Note ~~17—~~16—Capital Stock for further discussion.

Cash used in financing activities totaled ~~$10~~$41 million for the ~~nine~~three months ended ~~September 30, 2014~~March 31, 2015 primarily due ~~primarily~~ to ~~$13~~(i) $23 million in repayments associated with repurchase agreements related to emission credits, (ii) $7 million in dividend payments on our Mandatory Convertible Preferred Stock, (iii) $4 million in interest rate swap settlement payments, $6(iv) $4 million in released restricted stock units for payment of employee withholding taxes in connection with our stock award plans, and (v) $2 million in principal payments ofon borrowings on the Tranche B-2 Term Loan and $2 million in financing costs in connection with the Credit Agreement, Senior Notes and the Macquarie Bank letter of credit, offset by $12 million in proceeds received related to the Emissions Repurchase Agreement.Loan. Please read Note ~~13—~~12—Debt for further discussion.

Future Financing Cash ~~Flow from Financing Activities.~~Flows. ~~As a result of our issuance of $400 million of mandatory convertible preferred stock on October 14, 2014, we~~We are obligated to pay dividends on our mandatory convertible preferred stock of $5.4 million quarterly on a cumulative basis when declared by our Board of Directors or upon conversion. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock or by delivery of any combination of cash and shares of our common stock. Our future cash flows from financing activities will include principal payments on our debt instruments as they become due, as well as periodic payments to settle our interest rate swap agreements. ~~In addition, our future cash flows from financing activities will be impacted by our share repurchase program.~~ Please read Note ~~17—~~16—Capital Stock for further discussion. Our future cash flows will be increased by proceeds from the debt issued by Atlas Power for the Delta Transaction and the issuance of our common stock to ECP.

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. Please read Note ~~11—~~12—Debt in our Form 10-K for further discussion.

~~Table of Contents~~

Financial Covenants

Credit Agreement. ~~On April 23, 2013, we entered into the Credit Agreement. The~~Our 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 uses 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the following ratios for the respective periods:

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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, as defined within the Credit Agreement, we may only apply a maximum of $150 million in cash to our outstanding secured debt.

Our revolver usage at ~~September 30, 2015~~March 31, 2016 was 3031 percent of the aggregate revolver commitment due to outstanding ~~letters of credit;~~LCs; therefore, we ~~were required to test~~tested the ~~covenant. Based on the calculation outlined in the Credit Agreement, we~~covenant and were in compliance at ~~September 30, 2015.~~March 31, 2016.

Genco Senior Notes. ~~On December 2, 2013, in connection with the acquisition of AER, 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. 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.

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 external, third-party ~~external~~ sources are included in the definition of indebtedness and are subject to these incurrence tests.

Based on ~~September 30, 2015~~March 31, 2016 calculations, ~~Genco’s interest coverage ratios are less than~~Genco did not meet the minimum ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources.

Please read Note ~~13—~~12—Debt for further discussion.

Dividends. We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determinations to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board of Directors.

We pay quarterly dividends on our Mandatory Convertible Preferred Stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the ~~period from January 1, 2015 to September 30,~~three months ended March 31, 2016 and 2015, we paid an aggregate of ~~$17~~$5 million and $7 million in ~~dividends. On October~~dividends on February 1, 2016 and February 2, 2015, respectively.

On April 1, 2016, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate. WeThe dividend is for the dividend period beginning on February 1, 2016 and ending on April 30, 2016. Such dividends were paid ~~no dividends during 2014. Please read Note 17—Capital Stock for further discussion.~~on May 2, 2016 to stockholders of record as of April 15, 2016.

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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	Ba3	BB
Senior Unsecured	B3	B+
Genco:
Senior Unsecured	B3Caa3	CCC+

~~On September 25, 2015, Moody’s affirmed Dynegy Inc.’s existing ratings and upgraded their outlook from stable to positive.~~

~~Table of Contents~~

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results

In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the three ~~and nine~~ months ended ~~September 30, 2015~~March 31, 2016 and ~~2014.~~2015. 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). All references to hedging within this Form 10-Q relate to economic hedging activities as we do not elect hedge accounting.

We completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of our newly acquired plants within our Coal and Gas segments are not included in our consolidated results for the three months ended March 31, 2015. Please read Note 3—Acquisitions—ECP Purchase Agreements and Duke Midwest Purchase Agreement for further discussion.

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Consolidated Summary Financial Information — Three Months Ended ~~September 30, 2015~~March 31, 2016 Compared to Three Months Ended ~~September 30, 2014~~March 31, 2015

The following table provides summary financial data regarding our unaudited consolidated results of operations for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively:


	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change			Three Months Ended March 31,							Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(amounts in millions)	2015			2014						Favorable (Unfavorable) % Change		2016				2015				Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Revenues	$	1,232		$	615		Favorable (Unfavorable) $ Change	$	617		100	%
Energy													$	803			$	543		$	260		48	%
Capacity													201				51			150			NM
Mark-to-market income, net													112				31			81			NM
Contract amortization													(17		)		(6		)	(11		)	(183	)%
Other (1)													24				13			11			85	%
Total revenues													1,123				632			491			78	%
Cost of sales, excluding depreciation expense	(621		)	(387		)	(234		)	(60	)%		(545		)		(377		)	(168		)	(45	)%
Gross margin	611			228			383			168	%		578				255			323			127	%
Operating and maintenance expense	(219		)	(114		)	(105		)	(92	)%		(221		)		(111		)	(110		)	(99	)%
Depreciation expense	(174		)	(61		)	(113		)	(185	)%		(171		)		(64		)	(107		)	(167	)%
Impairments and other charges	(74		)	—			(74		)	NM
Gain on sale of assets, net	—			3			(3		)	(100	)%
General and administrative expense	(29		)	(25		)	(4		)	(16	)%		(37		)		(30		)	(7		)	(23	)%
Acquisition and integration costs	(8		)	(9		)	1			11	%		(4		)		(90		)	86			96	%
Operating income	107			22			85			NM
Losses from unconsolidated investments	(4		)	—			(4		)	NM
Operating income (loss)													145				(40		)	185			NM
Earnings from unconsolidated investments													2				—			2			NM
Interest expense	(145		)	(32		)	(113		)	NM			(142		)		(136		)	(6		)	(4	)%
Other income and expense, net	46			5			41			NM			1				(5		)	6			120	%
Income (loss) before income taxes	4			(5		)	9			180	%		6				(181		)	187			103	%
Income tax expense	(28		)	—			(28		)	NM			(16		)		—			(16		)	NM
Net loss	(24		)	(5		)	(19		)	NM			(10		)		(181		)	171			94	%
Less: Net income attributable to noncontrolling interest	—			—			—			NM
Less: Net loss attributable to noncontrolling interest													—				(1		)	1			100	%
Net loss attributable to Dynegy Inc.	$	(24	)	$	(5	)	$	(19	)	NM			$	(10	)		$	(180	)	$	170		94	%


(1)	For the three months ended March 31, 2016 and 2015, respectively, Other includes $14 million and $10 million in ancillary services, $3 million and $1 million in tolling revenue, and $7 million and $2 million in RMR and other miscellaneous items.

The following tables provide summary financial data regarding our operating income (loss) by segment for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively:


	Three Months Ended September 30, 2015															Three Months Ended March 31, 2016
(amounts in millions)	Coal			IPH			Gas			Other			Total			Coal			IPH			Gas			Other			Total
Revenues	$	396		$	221		$	615		$	—		$	1,232		$	380		$	167		$	576		$	—		$	1,123
Cost of sales, excluding depreciation expense	(201		)	(133		)	(287		)	—			(621		)	(176		)	(99		)	(270		)	—			(545		)
Gross margin	195			88			328			—			611			204			68			306			—			578
Operating and maintenance expense	(118		)	(49		)	(50		)	(2		)	(219		)	(111		)	(45		)	(64		)	(1		)	(221		)
Depreciation expense	(39		)	(8		)	(126		)	(1		)	(174		)	(39		)	(9		)	(122		)	(1		)	(171		)
Impairments and other charges	(74		)	—			—			—			(74		)
General and administrative expense	—			—			—			(29		)	(29		)	—			—			—			(37		)	(37		)
Acquisition and integration costs	—			—			—			(8		)	(8		)	—			—			—			(4		)	(4		)
Operating income (loss)	$	(36	)	$	31		$	152		$	(40	)	$	107		$	54		$	14		$	120		$	(43	)	$	145

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	Three Months Ended September 30, 2014															Three Months Ended March 31, 2015
(amounts in millions)	Coal			IPH			Gas			Other			Total			Coal			IPH			Gas			Other			Total
Revenues	$	137		$	236		$	242		$	—		$	615		$	142		$	219		$	271		$	—		$	632
Cost of sales, excluding depreciation expense	(85		)	(158		)	(144		)	—			(387		)	(88		)	(138		)	(151		)	—			(377		)
Gross margin	52			78			98			—			228			54			81			120			—			255
Operating and maintenance expense	(40		)	(49		)	(25		)	—			(114		)	(37		)	(51		)	(23		)	—			(111		)
Depreciation expense	(14		)	(10		)	(36		)	(1		)	(61		)	(10		)	(8		)	(45		)	(1		)	(64		)
Gain on sale of assets, net	—			—			3			—			3
General and administrative expense	—			—			—			(25		)	(25		)	—			—			—			(30		)	(30		)
Acquisition and integration costs	—			—			—			(9		)	(9		)	—			—			—			(90		)	(90		)
Operating income (loss)	$	(2	)	$	19		$	40		$	(35	)	$	22		$	7		$	22		$	52		$	(121	)	$	(40	)

Discussion of Consolidated Results of Operations

Revenues. Consolidated revenues increased $491 million from $632 million during the three months ended March 31, 2015 to $1,123 million during the three months ended March 31, 2016. Our newly acquired plants, higher capacity revenues, and higher mark-to-market gains on hedging transactions contributed to increased revenues. This was partially offset by lower revenues ~~while mild temperatures have lowered demand in our generation areas, resulting in~~due to lower volumes and ~~unhedged~~energy prices realized by our legacy plants compared to 2014. Revenues increased by $617 million from $615 million for the three months ended September 30, 2014 to $1,232 million for the three months ended September 30, 2015. Gas segment revenues increased by $373 million, driven by $360 million from the newly acquired plants and $13 million from our legacy plants. This $13 million increase was primarily driven by $28 million in gains on derivative instruments, $13 million higher market capacity revenues and $5 million in lower contract amortization and other revenues, partially offset by $33 million lower revenue due to the expiration of the ConEd contract at Independence. Coal segment revenues increased by $259 million, driven by $229 million from the newly acquired plants and $30 million from our legacy plants. The $30 million increase in revenues from our legacy plants was primarily driven by $30 million in gains on derivative instruments, $11 million in higher retail and other revenues and $5 million of higher wholesale capacity revenues, offset by $16 million due to lower energy prices. IPH segment revenues decreased by $15 million primarily due to $57 million in lower energy revenues as a result of ~~lower generation volumes and power prices, partially offset~~mild winter weather across our key markets.

The following table summarizes the change in revenues by ~~$23 million in higher wholesale capacity revenue, $8 million in gains on derivative instruments and $11 million in higher retail and other revenues.~~segment:



(amounts in millions)	Coal			IPH			Gas			Total
Revenues, net of hedges, attributable to our newly acquired plants	$	269		$	—		$	392		$	661
Lower revenues attributable to our legacy plants:
Lower energy revenues, net of settled hedges, due to lower generation volumes at the Coal and IPH segments and lower prices at the Gas segment	(42		)	(66		)	(80		)	(188		)
Higher wholesale capacity revenues due to higher pricing	4			23			3			30
Higher (lower) mark-to-market gains on hedging transactions	20			29			(7		)	42
Lower retail revenues, net of hedges	(14		)	(39		)	—			(53		)
Lower (higher) contract amortization	—			2			(1		)	1
Other	1			(1		)	(2		)	(2		)
Total change in revenues	$	238		$	(52	)	$	305		$	491

Cost of Sales. Cost of sales increased ~~by $234~~$168 million from ~~$387~~$377 million ~~for~~during the three months ended ~~September 30, 2014~~March 31, 2015 to ~~$621~~$545 million ~~for~~during the three months ended ~~September 30, 2015. Gas segment cost of sales increased by $143 million,~~March 31, 2016, primarily driven by ~~$167 million from the~~costs associated with our newly acquired plants, partially offset by ~~$24 million decrease~~lower costs from our legacy ~~plants. This $24 million decrease was~~plants primarily due to a reduction in natural gas prices ~~of $41 million, offset by higher generation volumes of $15 million~~ and higher other costs of $2 million. Coal segment cost of sales increased by $116 million, primarily driven by $113 million from the newly acquired plants and $3 million from our legacy plants due to higher retail and other costs. IPH segment cost of sales decreased by $25 million, driven by $38 million in lower coal and freight costs as a result of lower generation ~~volumes, partially offset~~volumes.

The following table summarizes the change in cost of sales by ~~$10 million in contract amortization.~~segment:



(amounts in millions)	Coal			IPH			Gas			Total
Cost of sales attributable to our newly acquired plants	$	105		$	—		$	180		$	285
Lower cost of sales attributable to our legacy plants:
Lower coal and freight costs due to lower generation volumes at the Coal and IPH segments and favorable contract rates at the Gas segment	(25		)	(43		)	(6		)	(74		)
Lower natural gas prices	—			—			(57		)	(57		)
Higher retail costs	7			2			—			9
Lower contract amortization due to the expiration of certain coal and gas transport contracts	1			2			2			5
Total change in cost of sales	$	88		$	(39	)	$	119		$	168

Operating and Maintenance Expense. Operating and maintenance (“O&M”) expense increased ~~by $105~~$110 million from ~~$114~~$111 million for the three months ended ~~September 30, 2014~~March 31, 2015 to ~~$219~~$221 million for the three months ended ~~September 30, 2015~~March 31, 2016 primarily due to ~~the~~our newly acquired plants.

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Depreciation Expense. Depreciation expense increased by ~~$113~~$107 million from ~~$61~~$64 million for the three months ended ~~September 30, 2014~~March 31, 2015 to ~~$174~~$171 million for the three months ended ~~September 30, 2015~~March 31, 2016 primarily due to ~~the~~our newly acquired plants.

~~Impairments and Other Charges.~~ Impairments and other charges of $74 million for the three months ended September 30, 2015 are due to our impairment of the Wood River generation facility. Please read Note 9—Property, Plant and Equipment for further discussion.

~~Gain on Sale of Assets.~~ ~~Gain on sale of assets decreased by $3 million primarily due to a $3 million gain from the sale of our 50 percent ownership interest in Black Mountain in 2014, not repeated in 2015.~~

General and Administrative Expense. General and administrative expense increased by $4$7 million from ~~$25~~$30 million for the three months ended ~~September 30, 2014~~March 31, 2015 to ~~$29~~$37 million for the three months ended ~~September 30, 2015.~~March 31, 2016. This increase was primarily due to higher overhead associated with the Acquisitions and higher legal fees.

Acquisition and Integration Costs. Acquisition and integration costs decreased by $1$86 million from $9$90 million for the three months ended ~~September 30, 2014~~March 31, 2015 to $8$4 million for the three months ended ~~September 30, 2015.~~March 31, 2016. Acquisition and integration costs for the three months ended March 31, 2016 consisted of advisory and consulting fees related to the Delta Stock Purchase Agreement and the Acquisitions of $3 million and $1 million, respectively. Acquisition and integration costs for the three months ended March 31, 2015 consisted of $48 million in Bridge Loan financing fees and $42 million in advisory and consulting fees related to the Acquisitions. Please read Note 3—Acquisitions for further discussion.

~~Losses~~Earnings from Unconsolidated Investments. ~~Losses~~Earnings from unconsolidated investments increased by $4$2 million from earnings of zero for the three months ended ~~September 30, 2014~~March 31, 2015 to $4earnings of $2 million for the three months ended ~~September 30, 2015.~~March 31, 2016. We recorded $4$2 million in ~~losses~~earnings from our 50 percent Elwood investment during the three months ended ~~September 30, 2015.~~March 31, 2016.

Interest Expense. Interest expense increased by ~~$113~~$6 million from ~~$32~~$136 million for the three months ended ~~September 30, 2014~~March 31, 2015 to ~~$145~~$142 million for the three months ended ~~September 30, 2015~~March 31, 2016 primarily due to ~~the issuance~~amortization of ~~debt in October 2014 to finance the Acquisitions.~~financing costs and fees associated with our revolving facilities. Please read Note ~~13—~~12—Debt for further discussion.

Other Income and Expense, net. Other income and expense, net increased by ~~$41~~$6 million from ~~income~~expense of $5 million for the three months ended ~~September 30, 2014~~March 31, 2015 to income of ~~$46~~$1 million for the three months ended ~~September 30, 2015. The increase was~~March 31, 2016 primarily due to the change in fair value of our common stock warrants.

Income Tax Expense. We reported an income tax expense of ~~$28~~$16 million and zero for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively. ~~During~~Income tax expense for the three months ended ~~September 30, 2015, we reduced the deferred~~March 31, 2016 was primarily due to state income tax ~~liability assumed through the Acquisitions by $24 million,~~ resulting ~~in an offsetting reduction of the previously recognized release of the valuation allowance by $21 million. In addition, we recorded an additional tax expense of $7 million for discreet items including~~from a ~~state law~~ change in ~~Connecticut and the application of~~ our ~~effective state~~corporate tax ~~rates for jurisdictions for which we do not record a valuation allowance. Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.~~structure.

As of ~~September 30, 2015,~~March 31, 2016, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise, as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future. Please read Note 14—Income Taxes for further discussion.

Discussion of Adjusted EBITDA

Non-GAAP Performance Measures. In analyzing and planning for our business, we supplement our use of the Generally Accepted Accounting Principles of the United States of America (“GAAP”) financial measures with non-GAAP financial measures, including earnings before interest, taxes, depreciation, and amortization (“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,

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as well as interest rate swaps and warrants, (iii) the impact of impairment charges and certain other costs such as those associated with acquisitions, and (iv) ~~income or expense on up-front premiums received or paid for financial options~~other material items. Beginning in ~~periods other than the strike periods, (v) income or loss attributable to noncontrolling interest and (vi) earnings or losses from unconsolidated investments.~~2016, Adjusted EBITDA also ~~includes cash distributions from our unconsolidated investments.~~excludes non-cash compensation expense. Non-cash compensation expense of $6 million was not excluded during the three months ended 2015.

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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 EBITDA or 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 EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss).

Adjusted EBITDA — Three Months Ended ~~September 30, 2015~~March 31, 2016 Compared to Three Months Ended ~~September 30, 2014~~March 31, 2015

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended ~~September 30, 2015:~~March 31, 2016:


	Three Months Ended September 30, 2015															Three Months Ended March 31, 2016
(amounts in millions)	Coal			IPH			Gas			Other			Total			Coal				IPH			Gas			Other			Total
Net loss attributable to Dynegy Inc.													$	(24	)														$	(10	)
Income tax expense													28																16
Other items, net(1)													(46		)														(1		)
Interest expense													145																142
Losses from unconsolidated investments													4
Earnings from unconsolidated investments																													(2		)
Operating income (loss)	$	(36	)	$	31		$	152		$	(40	)	$	107		$	54			$	14		$	120		$	(43	)	$	145
Depreciation expense	39			8			126			1			174			39				9			122			1			171
Amortization expense	(13		)	(5		)	13			—			(5		)	(12		)		(1		)	27			—			14
Losses from unconsolidated investments	—			—			(4		)	—			(4		)
Earnings from unconsolidated investments																—			��	—			2			—			2
Other items, net	—			—			—			46			46			—				—			—			1			1
EBITDA	(10		)	34			287			7			318			81				22			271			(41		)	333
Earnings from unconsolidated investments																—				—			(2		)	—			(2		)
Cash distributions from unconsolidated investments																—				—			5			—			5
Acquisition and integration costs	—			—			—			8			8			—				—			—			4			4
Mark-to-market adjustments	(14		)	(3		)	(6		)	—			(23		)	(40		)		(3		)	(62		)	—			(105		)
Change in fair value of common stock warrants	—			—			—			(45		)	(45		)	—				—			—			(1		)	(1		)
Impairments and other charges	74			—			—			—			74
Cash distributions from unconsolidated investments	—			—			8			—			8
ARO accretion expense																3				2			—			—			5
Wood River energy margin and O&M																5				—			—			—			5
Non-cash compensation expense																—				—			1			6			7
Other	4			3			2			1			10			1				—			(1		)	—			—
Adjusted EBITDA	$	54		$	34		$	291		$	(29	)	$	350		$	50			$	21		$	212		$	(32	)	$	251


(1)	Other items, net primarily consists of the change in fair value of our common stock warrants.

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The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended ~~September 30, 2014:~~March 31, 2015:


	Three Months Ended September 30, 2014															Three Months Ended March 31, 2015
(amounts in millions)	Coal			IPH			Gas			Other			Total			Coal			IPH			Gas			Other			Total
Net loss attributable to Dynegy Inc.													$	(5	)													$	(180	)
Other items, net													(5		)
Loss attributable to noncontrolling interest																												(1		)
Other items, net (1)																												5
Interest expense													32															136
Operating income (loss)	$	(2	)	$	19		$	40		$	(35	)	$	22		$	7		$	22		$	52		$	(121	)	$	(40	)
Depreciation expense	14			10			36			1			61			10			8			45			1			64
Amortization expense	(1		)	(13		)	21			—			7			(1		)	(1		)	(2		)	—			(4		)
Other items, net	—			1			—			4			5			—			—			—			(5		)	(5		)
EBITDA	11			17			97			(30		)	95			16			29			95			(125		)	15
Acquisition and integration costs	—			—			—			9			9			—			—			—			90			90
Loss attributable to noncontrolling interest																—			1			—			—			1
Mark-to-market adjustments	(12		)	(4		)	5			—			(11		)	(7		)	(11		)	(13		)	—			(31		)
Change in fair value of common stock warrants	—			—			—			(6		)	(6		)	—			—			—			5			5
Gain on sale of assets, net	—			—			(3		)	—			(3		)
ARO accretion expense																1			3			—			—			4
Other	2			2			(1		)	3			6			—			—			—			1			1
Adjusted EBITDA	$	1		$	15		$	98		$	(24	)	$	90		$	10		$	22		$	82		$	(29	)	$	85


(1)	Other items, net primarily consists of the change in fair value of our common stock warrants.

Adjusted EBITDA ~~increased by $260 million from $90~~was $85 million for the three months ended ~~September 30, 2014~~March 31, 2015 compared to ~~$350~~$251 million for the three months ended ~~September 30, 2015.~~March 31, 2016. The $166 million increase in Adjusted EBITDA was due to $209 million from our newly acquired plants, partially offset by a $43 million decrease from our legacy plants. The decrease from our legacy plants was driven by lower energy margin, net of hedges, in all segments primarily due to lower generation volumes at the ~~newly acquired plants~~Coal and ~~higher~~IPH segments, and lower spark spreads at the Gas segment ~~higher wholesale capacity revenues at the IPH and Coal segments and improved results for the retail business,~~as a result of mild winter weather across our key markets. This decrease was partially offset by ~~the expiration of the ConEd contract at Independence at the Gas segment.~~higher capacity revenues in all segments. Please read Discussion of Segment Adjusted EBITDA for further information.

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Discussion of Segment Adjusted EBITDA — Three Months Ended ~~September 30, 2015~~March 31, 2016 Compared to Three Months Ended ~~September 30, 2014~~March 31, 2015

Coal Segment

The following table provides summary financial data regarding our Coal segment results of operations for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively:


	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change			Three Months Ended March 31,							Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price information)	2015			2014						Favorable (Unfavorable) % Change		2016				2015				Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Operating Revenues							Favorable (Unfavorable) $ Change
Operating revenues
Energy	$	318		$	131		$	187		143	%		$	281			$	133		$	148		111	%
Capacity	53			—			53			NM			52				2			50			NM
Mark-to-market income, net	21			12			9			75	%		47				7			40			NM
Contract amortization	(7		)	—			(7		)	NM			(2		)		—			(2		)	NM
Other (1)	11			(6		)	17			NM			2				—			2			NM
Total operating revenues	396			137			259			189	%		380				142			238			168	%
Operating Costs
Operating costs
Cost of sales	(221		)	(86		)	(135		)	(157	)%		(189		)		(89		)	(100		)	(112	)%
Contract amortization	20			1			19			NM			13				1			12			NM
Total operating costs	(201		)	(85		)	(116		)	(136	)%		(176		)		(88		)	(88		)	(100	)%
Gross margin	195			52			143			NM			204				54			150			NM
Operating and maintenance expense	(118		)	(40		)	(78		)	(195	)%		(111		)		(37		)	(74		)	(200	)%
Depreciation expense	(39		)	(14		)	(25		)	(179	)%		(39		)		(10		)	(29		)	NM
Impairments and other charges	(74		)	—			(74		)	NM
Operating loss	(36		)	(2		)	(34		)	NM
Operating income													54				7			47			NM
Depreciation expense	39			14			25			179	%		39				10			29			NM
Amortization expense	(13		)	(1		)	(12		)	NM			(12		)		(1		)	(11		)	NM
EBITDA	(10		)	11			(21		)	(191	)%		81				16			65			NM
Mark-to-market adjustments	(14		)	(12		)	(2		)	(17	)%		(40		)		(7		)	(33		)	NM
Impairments and other charges	74			—			74			NM
ARO accretion expense													3				1			2			200	%
Wood River energy margin and O&M													5				—			5			NM
Other	4			2			2			100	%		1				—			1			NM
Adjusted EBITDA	$	54		$	1		$	53		NM			$	50			$	10		$	40		NM

Million Megawatt Hours Generated ~~(5)~~	9.5			4.5			5.0			111	%		7.6				4.8			2.8			58	%
IMA for Coal-Fired Facilities ~~(5)~~(2)	82		%	81		%							81		%		91		%
Average Capacity Factor for Coal-Fired Facilities ~~(5)~~(3)	62		%	69		%							46		%		74		%
Average Quoted Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	33.09		$	37.90		$	(4.81	)	(13	)%		$	25.61			$	39.27		$	(13.66	)	(35	)%
Commonwealth Edison (NI Hub)	$	34.03		$	37.58		$	(3.55	)	(9	)%		$	27.35			$	40.82		$	(13.47	)	(33	)%
Mass Hub	$	35.52		$	42.01		$	(6.49	)	(15	)%		$	33.85			$	96.19		$	(62.34	)	(65	)%
AD Hub	$	35.87		$	39.02		$	(3.15	)	(8	)%		$	28.80			$	45.26		$	(16.46	)	(36	)%
Average Quoted Market Off-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	23.37		$	27.57		$	(4.20	)	(15	)%		$	20.18			$	28.97		$	(8.79	)	(30	)%
Commonwealth Edison (NI Hub)	$	22.93		$	25.40		$	(2.47	)	(10	)%		$	20.55			$	27.85		$	(7.30	)	(26	)%
Mass Hub	$	21.02		$	27.01		$	(5.99	)	(22	)%		$	26.21			$	76.43		$	(50.22	)	(66	)%
AD Hub	$	24.21		$	27.91		$	(3.70	)	(13	)%		$	22.92			$	32.27		$	(9.35	)	(29	)%

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(1)	For the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively, Other includes ~~$8 million and ($7) million in financial settlements, $1 million and zero in natural gas sales,~~ $1 million and zero in ancillary services and $1 million and ~~$1 million~~zero in other miscellaneous items.

(2)

IMA 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. The ~~2015~~2016 calculation excludes our Brayton Point facility and CTs. In ~~2015,~~2016, the IMA for our facilities within MISO and PJM (excluding CTs) was 9189 percent and 77 percent, respectively.


(3)	Reflects actual production as a percentage of available capacity. The ~~2015~~2016 calculation excludes our Brayton Point facility and CTs. In ~~2015,~~2016, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 6850 percent and 5743 percent, respectively.


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


~~(5)~~	~~Reflects the activity for the period in which the Acquisitions were included in our consolidated results.~~

Operating ~~loss~~income for the three months ended ~~September 30, 2015~~March 31, 2016 was ~~$36~~$54 million compared to $2$7 million for the three months ended ~~September 30, 2014.~~March 31, 2015. Adjusted EBITDA was ~~$54~~$50 million ~~during~~for the three months ended ~~September 30, 2015~~March 31, 2016 compared to $1$10 million ~~during~~for the ~~same period in 2014.~~three months ended March 31, 2015. The ~~$53~~$40 million increase in Adjusted EBITDA was due to $56 million from our newly acquired plants, partially offset by a $16 million decrease from our legacy plants, excluding Wood River. The decrease from our legacy plants was driven by lower energy margin, net of hedges, primarily due to ~~the newly acquired plants, improved~~lower generation volumes as a result of mild winter weather and higher O&M costs. This decrease was partially offset by higher wholesale capacity ~~revenues and higher realized power prices, net of hedges, on the legacy MISO fleet.~~revenues.

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IPH Segment

The following table provides summary financial data regarding our IPH segment results of operations for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively:


	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change			Three Months Ended March 31,							Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price information)	2015			2014						Favorable (Unfavorable) % Change		2016				2015				Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Operating Revenues							Favorable (Unfavorable) $ Change
Operating revenues
Energy	$	173		$	224		$	(51	)	(23	)%		$	128			$	196		$	(68	)	(35	)%
Capacity	41			18			23			128	%		39				16			23			144	%
Mark-to-market income, net	3			4			(1		)	(25	)%		3				11			(8		)	(73	)%
Contract amortization	(4		)	(6		)	2			33	%		(4		)		(6		)	2			33	%
Other (1)	8			(4		)	12			NM			1				2			(1		)	(50	)%
Total operating revenues	221			236			(15		)	(6	)%		167				219			(52		)	(24	)%
Operating Costs
Operating costs
Cost of sales	(142		)	(177		)	35			20	%		(104		)		(145		)	41			28	%
Contract amortization	9			19			(10		)	(53	)%		5				7			(2		)	(29	)%
Total operating costs	(133		)	(158		)	25			16	%		(99		)		(138		)	39			28	%
Gross margin	88			78			10			13	%		68				81			(13		)	(16	)%
Operating and maintenance expense	(49		)	(49		)	—			—	%		(45		)		(51		)	6			12	%
Depreciation expense	(8		)	(10		)	2			20	%		(9		)		(8		)	(1		)	(13	)%
Operating income	31			19			12			63	%		14				22			(8		)	(36	)%
Depreciation expense	8			10			(2		)	(20	)%		9				8			1			13	%
Amortization expense	(5		)	(13		)	8			62	%		(1		)		(1		)	—			NM
Other items, net	—			1			(1		)	(100	)%
EBITDA	34			17			17			100	%		22				29			(7		)	(24	)%
Income attributable to noncontrolling interest													—				1			(1		)	(100	)%
Mark-to-market adjustments	(3		)	(4		)	1			25	%		(3		)		(11		)	8			73	%
Other	3			2			1			50	%
ARO accretion expense													2				3			(1		)	(33	)%
Adjusted EBITDA	$	34		$	15		$	19		127	%		$	21			$	22		$	(1	)	(5	)%

Million Megawatt Hours Generated	4.8			6.4			(1.6		)	(25	)%		3.3				5.2			(1.9		)	(37	)%
IMA for IPH Facilities (2)	84		%	93		%							86		%		93		%
Average Capacity Factor for IPH Facilities (3)	54		%	74		%							39		%		60		%
Average Quoted Market Power Prices ($/MWh) (4):
On-Peak: Indiana (Indy Hub)	$	33.09		$	37.90		$	(4.81	)	(13	)%		$	25.61			$	39.27		$	(13.66	)	(35	)%
Off-Peak: Indiana (Indy Hub)	$	23.37		$	27.57		$	(4.20	)	(15	)%		$	20.18			$	28.97		$	(8.79	)	(30	)%


(1)	For the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively, Other includes $6$2 million and ~~($2) million in financial settlements, $1 million and ($2) million~~zero in ancillary services and $1($1) million and ~~zero~~$2 million in other miscellaneous items.


(2)	IMA 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.


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


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

Operating income for the three months ended ~~September 30, 2015~~March 31, 2016 was ~~$31~~$14 million compared to ~~$19~~$22 million for the three months ended ~~September 30, 2014.~~March 31, 2015. Adjusted EBITDA was ~~$34~~$21 million ~~during~~for the three months ended ~~September 30, 2015~~March 31, 2016 compared to $22 million for the three months ended March 31, 2015. The $1 million decrease in Adjusted EBITDA resulted from lower energy margin, net of hedges, primarily due to lower generation volumes driven primarily by mild winter weather as well as lower retail

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~~compared to $15 million during the same period in 2014. The $19 million increase in Adjusted EBITDA resulted from~~margin. This decrease was partially offset by higher wholesale capacity revenues and ~~higher retail gross margin.~~lower O&M costs primarily due to fewer planned outages.

Gas Segment

The following table provides summary financial data regarding our Gas segment results of operations for the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively:


	Three Months Ended September 30,						Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change			Three Months Ended March 31,							Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
(dollars in millions, except for price information)	2015			2014						Favorable (Unfavorable) % Change		2016				2015				Favorable (Unfavorable) $ Change			Favorable (Unfavorable) % Change
Operating Revenues							Favorable (Unfavorable) $ Change
Energy	$	443		$	172		$	271		158	%		$	394			$	214		$	180		84	%
Capacity	136			80			56			70	%		110				33			77			233	%
Mark-to-market income (loss), net	32			(5		)	37			NM
Mark-to-market income, net													62				13			49			NM
Contract amortization	(14		)	(23		)	9			39	%		(11		)		—			(11		)	NM
Other (1)	18			18			—			—	%		21				11			10			91	%
Total operating revenues	615			242			373			154	%		576				271			305			113	%
Operating Costs
Cost of sales	(288		)	(146		)	(142		)	(97	)%		(254		)		(153		)	(101		)	(66	)%
Contract amortization	1			2			(1		)	(50	)%		(16		)		2			(18		)	NM
Total operating costs	(287		)	(144		)	(143		)	(99	)%		(270		)		(151		)	(119		)	(79	)%
Gross margin	328			98			230			235	%		306				120			186			155	%
Operating and maintenance expense	(50		)	(25		)	(25		)	(100	)%		(64		)		(23		)	(41		)	(178	)%
Depreciation expense	(126		)	(36		)	(90		)	NM			(122		)		(45		)	(77		)	(171	)%
Gain on sale of assets, net	—			3			(3		)	(100	)%
Operating income	152			40			112			NM			120				52			68			131	%
Depreciation expense	126			36			90			NM			122				45			77			171	%
Amortization expense	13			21			(8		)	(38	)%		27				(2		)	29			NM
Losses from unconsolidated investments	(4		)	—			(4		)	NM
Earnings from unconsolidated investments													2				—			2			NM
EBITDA	287			97			190			196	%		271				95			176			185	%
Earnings from unconsolidated investments													(2		)		—			(2		)	NM
Cash distributions from unconsolidated investments													5				—			5			NM
Mark-to-market adjustments	(6		)	5			(11		)	(220	)%		(62		)		(13		)	(49		)	NM
Gain on sale of assets, net	—			(3		)	3			100	%
Cash distributions from unconsolidated investments	8			—			8			NM
Non-cash compensation expense													1				—			1			NM
Other	2			(1		)	3			NM			(1		)		—			(1		)	NM
Adjusted EBITDA	$	291		$	98		$	193		197	%		$	212			$	82		$	130		159	%

Million Megawatt Hours Generated (2) (7)	15.5			4.8			10.7			223	%
IMA for Combined Cycle Facilities (3) (7)	99		%	99		%
Average Capacity Factor for Combined Cycle Facilities (4) (7):	72		%	51		%
Average Market On-Peak Spark Spreads ($/MWh) (5):
Million Megawatt Hours Generated													13.3				5.0			8.3			166	%
IMA for Combined Cycle Facilities (2)													96		%		99		%
Average Capacity Factor for Combined Cycle Facilities (3)													62		%		52		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	14.49		$	9.65		$	4.84		50	%		$	13.06			$	17.68		$	(4.62	)	(26	)%
PJM West	$	29.82		$	26.30		$	3.52		13	%		$	18.72			$	17.55		$	1.17		7	%
North of Path 15 (NP 15)	$	16.25		$	19.40		$	(3.15	)	(16	)%		$	10.72			$	12.67		$	(1.95	)	(15	)%
New York—Zone A	$	26.32		$	24.58		$	1.74		7	%		$	16.70			$	39.80		$	(23.10	)	(58	)%
Mass Hub	$	18.90		$	21.22		$	(2.32	)	(11	)%		$	10.83			$	14.92		$	(4.09	)	(27	)%
AD Hub	$	27.28		$	23.17		$	4.11		18	%		$	19.83			$	31.12		$	(11.29	)	(36	)%
Average Market Off-Peak Spark Spreads ($/MWh) (5):
Average Market Off-Peak Spark Spreads ($/MWh) (4):
Commonwealth Edison (NI Hub)	$	3.39		$	(2.53	)	$	5.92		234	%		$	6.26			$	4.71		$	1.55		33	%
PJM West	$	15.50		$	12.48		$	3.02		24	%		$	12.81			$	0.98		$	11.83		NM
North of Path 15 (NP 15)	$	8.22		$	8.55		$	(0.33	)	(4	)%		$	6.03			$	7.25		$	(1.22	)	(17	)%
New York—Zone A	$	10.49		$	9.26		$	1.23		13	%		$	4.92			$	25.32		$	(20.40	)	(81	)%
Mass Hub	$	4.39		$	6.22		$	(1.83	)	(29	)%		$	3.19			$	(4.84	)	$	8.03		166	%
AD Hub	$	15.62		$	12.07		$	3.55		29	%		$	13.95			$	18.13		$	(4.18	)	(23	)%
Average natural gas price—Henry Hub ($/MMBtu) ~~(6)~~(5)	$	2.74		$	3.94		$	(1.20	)	(30	)%		$	1.98			$	2.87		$	(0.89	)	(31	)%

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(1)

For the three months ended ~~September 30,~~March 31, 2016 and 2015, ~~and 2014,~~ respectively, Other includes ~~($25)~~$11 million and ~~($2) million in financial settlements, $12 million and $4 million in natural gas sales, $13 million and $5~~$10 million in ancillary services, $9$3 million and $8$1 million in ~~tolls~~tolling revenue and $9$7 million and ~~$3 million~~zero in RMR ~~option premiums~~ and other miscellaneous items.


(2)	~~The three months ended September 30, 2014 includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility which was sold on June 27, 2014.~~


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


~~(5)~~(4)	Reflects the simple average of the on- and off-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.


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


~~(7)~~	~~Reflects the activity for the period in which the Acquisitions were included in our consolidated results.~~

Operating income for the three months ended September 30, 2015 was $152 million compared to $40 million for the three months ended September 30, 2014. Adjusted EBITDA totaled $291 million during the three months ended September 30, 2015 compared to $98 million during the same period in 2014. The $193 million increase in Adjusted EBITDA was primarily due to the newly acquired plants, higher hedged energy margin and improved market capacity and tolling revenue, partially offset by the expiration of the ConEd contract at Independence.

~~Consolidated Summary Financial Information — Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014~~

~~The following table provides summary financial data regarding our consolidated results of operations for the nine months ended September 30, 2015 and 2014, respectively:~~

Nine Months Ended September 30, Favorable (Unfavorable) $ Change Favorable (Unfavorable) % Change
(amounts in millions) 2015 2014
Revenues $ 2,854
$ 1,898
$ 956
50 %
Cost of sales, excluding depreciation expense (1,494 ) (1,304 ) (190 ) (15 )%
Gross margin 1,360
594
766
129 %
Operating and maintenance expense (580 ) (360 ) (220 ) (61 )%
Depreciation expense (413 ) (185 ) (228 ) (123 )%
Impairments and other charges (74 ) —
(74 ) NM
Gain (loss) on sale of assets, net (1 ) 17
(18 ) (106 )%
General and administrative expense (94 ) (80 ) (14 ) (18 )%
Acquisition and integration costs (121 ) (17 ) (104 ) NM
Operating income (loss) 77
(31 ) 108
NM
Earnings (losses) from unconsolidated investments (1 ) 10
(11 ) (110 )%
Interest expense (413 ) (104 ) (309 ) NM
Other income and expense, net 45
(40 ) 85
213 %
Loss before income taxes (292 ) (165 ) (127 ) (77 )%
Income tax benefit 473
1
472
NM
Net income (loss) 181
(164 ) 345
210 %
Less: Net income (loss) attributable to noncontrolling interest (3 ) 5
(8 ) (160 )%
Net income (loss) attributable to Dynegy Inc. $ 184
$ (169 ) $ 353
209 %

~~Table of Contents~~

~~The following tables provide summary financial data regarding our operating income (loss) by segment for the nine months ended September 30, 2015 and 2014, respectively:~~

Nine Months Ended September 30, 2015
(amounts in millions) Coal IPH Gas Other Total
Revenues $ 845
$ 625
$ 1,384
$ —
$ 2,854
Cost of sales, excluding depreciation expense (423 ) (402 ) (669 ) —
(1,494 )
Gross margin 422
223
715
—
1,360
Operating and maintenance expense (286 ) (160 ) (134 ) —
(580 )
Depreciation expense (96 ) (24 ) (290 ) (3 ) (413 )
Impairments and other charges (74 ) —
—
—
(74 )
Loss on sale of assets, net —
—
(1 ) —
(1 )
General and administrative expense —
—
—
(94 ) (94 )
Acquisition and integration costs —
—
—
(121 ) (121 )
Operating income (loss) $ (34 ) $ 39
$ 290
$ (218 ) $ 77

Nine Months Ended September 30, 2014
(amounts in millions) Coal IPH Gas Other Total
Revenues $ 429
$ 619
$ 850
$ —
$ 1,898
Cost of sales, excluding depreciation expense (270 ) (447 ) (587 ) —
(1,304 )
Gross margin 159
172
263
—
594
Operating and maintenance expense (118 ) (150 ) (93 ) 1
(360 )
Depreciation expense (39 ) (28 ) (115 ) (3 ) (185 )
Gain on sale of assets, net —
—
17
—
17
General and administrative expense —
—
—
(80 ) (80 )
Acquisition and integration costs —
(8 ) —
(9 ) (17 )
Operating income (loss) $ 2
$ (14 ) $ 72
$ (91 ) $ (31 )

~~Discussion of Consolidated Results of Operations~~

~~Revenues.~~ Our newly acquired plants contributed to increased revenues, while mild temperatures and increased precipitation levels have lowered demand in our generation areas, resulting in lower volumes and prices realized by our legacy plants, compared to 2014. Revenues increased by $956 million from $1,898 million for the nine months ended September 30, 2014 to $2,854 million for the nine months ended September 30, 2015. Gas segment revenues increased by $534 million, driven by $655 million from the newly acquired plants, partially offset by $121 million in lower revenues from our legacy plants. The $121 million decrease in revenues from our legacy plants was primarily driven by $267 million in lower energy revenues as a result of lower energy prices, $92 million in lower revenue due to the expiration of the ConEd contract at Independence, partially offset by $158 million in higher revenues from gains on derivatives, $39 million improved market capacity revenues and $41 million in lower contract amortization. Coal segment revenues increased by $416 million, driven by $416 million from the newly acquired plants as our legacy plants’ decrease in energy revenue was offset by gains on derivative instruments. IPH segment revenues increased by $6 million primarily due to higher revenues from gains on derivative instruments of $39 million, higher wholesale capacity revenues of $56 million, higher retail and other revenues of $130 million and contract amortization of $11 million, partially offset by $230 million lower energy revenues due to lower generation volumes and power prices.

~~Cost of Sales.~~ Cost of sales increased by $190 million from $1,304 million for the nine months ended September 30, 2014 to $1,494 million for the nine months ended September 30, 2015. Gas segment cost of sales increased by $82 million, driven by $308 million from the newly acquired plants, offset by $226 million primarily due to a reduction in natural gas prices from our legacy plants. Coal segment cost of sales increased by $153 million, driven by $180 million from the newly acquired plants, partially offset by $27 million from our legacy plants. The $27 million decrease in cost of sales from our legacy plants was primarily due to $33 million in lower coal and freight costs as a result of lower generation volumes, partially offset by $6 million due to higher retail and other costs. IPH segment cost of sales decreased by $45 million, driven by $74 million in lower coal and

~~Table of Contents~~

~~freight costs as a result of lower generation volumes, offset by $17 million in higher retail costs and $12 million in higher contract amortization.~~

~~Operating and Maintenance Expense.~~ Operating and maintenance expense increased by $220 million from $360 million for the nine months ended September 30, 2014 to $580 million for the nine months ended September 30, 2015 primarily due to the newly acquired plants.

~~Depreciation Expense.~~ Depreciation expense increased by $228 million from $185 million for the nine months ended September 30, 2014 to $413 million for the nine months ended September 30, 2015 primarily due to the newly acquired plants.

~~Impairments and Other Charges.~~ Impairments and other charges of $74 million for the nine months ended September 30, 2015 are due to our impairment of the Wood River generation facility. Please read Note 9—Property, Plant and Equipment for further discussion.

~~Gain (loss) on Sale of Assets.~~ ~~Gain (loss) on sale of assets decreased by $18 million primarily due to a $17 million gain from the sale of our 50 percent ownership interest in Black Mountain in 2014, not repeated in 2015.~~

~~General and Administrative Expense.~~ General and administrative expense increased by $14 million from $80 million for the nine months ended September 30, 2014 to $94 million for the nine months ended September 30, 2015. This increase was primarily due to higher overhead associated with the Acquisitions and higher legal fees.

~~Acquisition and Integration Costs.~~ Acquisition and integration costs increased by $104 million from $17 million for the nine months ended September 30, 2014 to $121 million for the nine months ended September 30, 2015. Acquisition and integration costs for the nine months ended September 30, 2015 consisted of $48 million in Bridge Loan financing fees and $61 million in advisory and consulting fees related to the Acquisitions and $12 million in severance costs. Acquisition and integration costs for the nine months ended September 30, 2014 consisted of $9 million in advisory and consulting fees related to the Acquisitions and $8 million related to the acquisition of AER. Please read Note 3—Acquisitions for further discussion.

~~Earnings (losses) from Unconsolidated Investments.~~ Earnings (losses) from unconsolidated investments decreased by $11 million from earnings of $10 million for the nine months ended September 30, 2014 to losses of $1 million for the nine months ended September 30, 2015. We received $10 million in cash distributions from Black Mountain during the nine months ended September 30, 2014 and recorded $1 million in losses from our 50 percent Elwood investment during the nine months ended September 30, 2015.

~~Interest Expense.~~ Interest expense increased by $309 million from $104 million for the nine months ended September 30, 2014 to $413 million for the nine months ended September 30, 2015 primarily due to the issuance of debt in October 2014 to finance the Acquisitions. Please read Note 13—Debt for further discussion.

~~Other Income and Expense, net.~~ Other income and expense, net increased by $85 million from expense of $40 million for the nine months ended September 30, 2014 to income of $45 million for the nine months ended September 30, 2015 primarily due to the change in fair value of our common stock warrants.

~~Income Tax Benefit.~~ We reported an income tax benefit of $473 million and $1 million for the nine months ended September 30, 2015 and 2014, respectively. We released $459 million of our valuation allowance as a result of increased net deferred tax liabilities related to the EquiPower Acquisition. In addition, we recorded an additional tax benefit of $14 million for discreet items including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance. Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.

As of September 30, 2015, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future.

~~Table of Contents~~

~~Adjusted EBITDA — Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014~~

~~The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine months ended September 30, 2015:~~

Nine Months Ended September 30, 2015
(amounts in millions) Coal IPH Gas Other Total
Net income attributable to Dynegy Inc. $ 184
Loss attributable to noncontrolling interest (3 )
Income tax benefit (473 )
Other items, net (45 )
Interest expense 413
Losses from unconsolidated investments 1
Operating income (loss) $ (34 ) $ 39
$ 290
$ (218 ) $ 77
Depreciation expense 96
24
290
3
413
Amortization expense (24 ) (6 ) 16
—
(14 )
Losses from unconsolidated investments —
—
(1 ) —
(1 )
Other items, net —
—
—
45
45
EBITDA 38
57
595
(170 ) 520
Acquisition and integration costs —
—
—
121
121
Loss attributable to noncontrolling interest —
3
—
—
3
Mark-to-market adjustments (35 ) (8 ) (29 ) —
(72 )
Change in fair value of common stock warrants —
—
—
(43 ) (43 )
Impairments and other charges 74
—
—
—
74
Loss on sale of assets, net —
—
1

—
1
Cash distributions from unconsolidated investments —
—
8
—
8
Other 6
9
—
1
16
Adjusted EBITDA $ 83
$ 61
$ 575
$ (91 ) $ 628

~~Table of Contents~~

~~The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine months ended September 30, 2014:~~

Nine Months Ended September 30, 2014
(amounts in millions) Coal IPH Gas Other Total
Net loss attributable to Dynegy Inc. $ (169 )
Income attributable to noncontrolling interest 5
Income tax benefit (1 )
Other items, net 40
Interest expense 104
Earnings from unconsolidated investments (10 )
Operating income (loss) $ 2
$ (14 ) $ 72
$ (91 ) $ (31 )
Depreciation expense 39
28
115
3
185
Amortization expense (4 ) (11 ) 57
—
42
Earnings from unconsolidated investments —
—
10
—
10
Other items, net —
1
—
(41 ) (40 )
EBITDA 37
4
254
(129 ) 166
Acquisition and integration costs —
8
—
9
17
Income attributable to noncontrolling interest —
(5 ) —
—
(5 )
Mark-to-market adjustments 7
34
23
—
64
Change in fair value of common stock warrants —
—
—
43
43
Gain on sale of assets, net —
—
(17 ) —
(17 )
Other 7
4
—
1
12
Adjusted EBITDA $ 51
$ 45
$ 260
$ (76 ) $ 280

Adjusted EBITDA increased by $348 million from $280 million for the nine months ended September 30, 2014 to $628 million for the nine months ended September 30, 2015. The increase was primarily due to the newly acquired plants, higher market capacity revenues and retail margin related to legacy plants at the Coal and IPH segments and higher spark spreads related to legacy plants at the Gas segment, partially offset by lower realized power prices on the unhedged power sales related to legacy plants at the Coal segment and the expiration of the ConEd contract at Independence at the Gas segment. Please read Discussion of Segment Adjusted EBITDA for further information.

~~Table of Contents~~

~~Discussion of Segment Adjusted EBITDA — Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014~~

~~Coal Segment~~

~~The following table provides summary financial data regarding our Coal segment results of operations for the nine months ended September 30, 2015 and 2014, respectively:~~

Nine Months Ended September 30, Favorable (Unfavorable) $ Change Favorable (Unfavorable) % Change
(dollars in millions, except for price information) 2015 2014
Operating Revenues

Energy $ 684
$ 506
$ 178
35 %
Capacity 103
3
100
NM
Mark-to-market income (loss), net 38
(7 ) 45
NM
Contract amortization (19 ) —
(19 ) NM
Other (1) 39
(73 ) 112
153 %
Total operating revenues 845
429
416
97 %
Operating Costs
Cost of sales (466 ) (274 ) (192 ) (70 )%
Contract amortization 43
4
39
NM
Total operating costs (423 ) (270 ) (153 ) (57 )%
Gross margin 422
159
263
165 %
Operating and maintenance expense (286 ) (118 ) (168 ) (142 )%
Depreciation expense (96 ) (39 ) (57 ) (146 )%
Impairments and other charges (74 ) —
(74 ) NM
Operating income (loss) (34 ) 2
(36 ) NM
Depreciation expense 96
39
57
146 %
Amortization expense (24 ) (4 ) (20 ) NM
EBITDA 38
37
1
3 %
Mark-to-market adjustments (35 ) 7
(42 ) NM
Impairments and other charges 74
—
74
NM
Other 6
7
(1 ) (14 )%
Adjusted EBITDA $ 83
$ 51
$ 32
63 %

Million Megawatt Hours Generated (5) 21.7
14.4
7.3
51 %
IMA for Coal-Fired Facilities (2)(5) 80 % 88 %
Average Capacity Factor for Coal-Fired Facilities (3)(5) 59 % 74 %
Average Quoted Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub) $ 35.17
$ 51.53
$ (16.36 ) (32 )%
Commonwealth Edison (NI Hub) $ 35.44
$ 54.95
$ (19.51 ) (36 )%
Mass Hub $ 53.62
$ 86.50
$ (32.88 ) (38 )%
AD Hub $ 39.86
$ 59.29
$ (19.43 ) (33 )%
Average Quoted Market Off-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub) $ 25.41
$ 33.68
$ (8.27 ) (25 )%
Commonwealth Edison (NI Hub) $ 23.49
$ 32.23
$ (8.74 ) (27 )%
Mass Hub $ 38.90
$ 61.25
$ (22.35 ) (36 )%
AD Hub $ 27.20
$ 36.38
$ (9.18 ) (25 )%

~~Table of Contents~~


~~(1)~~	For the nine months ended September 30, 2015 and 2014, respectively, Other includes $36 million and ($76) million in financial settlements, $2 million and zero in natural gas sales, ($1) million and $2 million in ancillary services and $2 million and $1 million in other miscellaneous items.

~~(2)~~

IMA 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. The 2015 calculation excludes our Brayton Point facility and CTs. In 2015, the IMA for our facilities within MISO and PJM (excluding CTs) was 87 percent and 73 percent, respectively.


~~(3)~~	Reflects actual production as a percentage of available capacity. The 2015 calculation excludes our Brayton Point facility and CTs. In 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 66 percent and 51 percent, respectively.


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


(5)	~~Reflects the activity for the period in which the Acquisitions were included in our consolidated results.~~

Operating loss for the nine months ended September 30, 2015 was $34 million compared to operating income of $2 million for the nine months ended September 30, 2014. Adjusted EBITDA was $83 million during the nine months ended September 30, 2015 compared to $51 million during the same period in 2014. The $32 million increase in Adjusted EBITDA was primarily due to a positive impact related to the newly acquired plants and improved capacity revenues related to legacy plants and retail margins, partially offset by lower power prices on the unhedged portion of the legacy MISO fleet and lower generation volumes driven primarily by mild temperatures and increased precipitation levels.

~~Table of Contents~~

~~IPH Segment~~

~~The following table provides summary financial data regarding our IPH segment results of operations for the nine months ended September 30, 2015 and 2014, respectively:~~

~~Table of Contents~~


~~(1)~~	For the nine months ended September 30, 2015 and 2014, respectively, Other includes $22 million and $25 million in financial settlements, $2 million and ($7) million in ancillary services and $4 million and ($1) million in other miscellaneous items.


~~(2)~~	IMA 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.


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


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

Operating income for the nine months ended September 30, 2015 was $39 million compared to an operating loss of $14 million for the nine months ended September 30, 2014. Adjusted EBITDA was $61 million during the nine months ended September 30, 2015 compared to $45 million during the same period in 2014. The $16 million increase in Adjusted EBITDA resulted from higher wholesale capacity revenues and higher retail gross margin, partially offset by lower generation volumes and lower power prices on unhedged power sales.

~~Table of Contents~~

~~Gas Segment~~

~~The following table provides summary financial data regarding our Gas segment results of operations for the nine months ended September 30, 2015 and 2014, respectively:~~

Nine Months Ended September 30, Favorable (Unfavorable) $ Change Favorable (Unfavorable) % Change
(dollars in millions, except for price information) 2015 2014
Operating Revenues

Energy $ 1,032
$ 743
$ 289
39 %
Capacity 270
193
77
40 %
Mark-to-market income (loss), net 74
(23 ) 97
NM
Contract amortization (21 ) (63 ) 42
67 %
Other (1) 29
—
29
NM
Total operating revenues 1,384
850
534
63 %
Operating Costs
Cost of sales (674 ) (593 ) (81 ) (14 )%
Contract amortization 5
6
(1 ) (17 )%
Total operating costs (669 ) (587 ) (82 ) (14 )%
Gross margin 715
263
452
172 %
Operating and maintenance expense (134 ) (93 ) (41 ) (44 )%
Depreciation expense (290 ) (115 ) (175 ) (152 )%
Gain (loss) on sale of assets, net (1 ) 17
(18 ) (106 )%
Operating income 290
72
218
NM
Depreciation expense 290
115
175
152 %
Amortization expense 16
57
(41 ) (72 )%
Earnings (losses) from unconsolidated investments (1 ) 10
(11 ) (110 )%
EBITDA 595
254
341
134 %
Mark-to-market adjustments (29 ) 23
(52 ) (226 )%
Gain (loss) on sale of assets, net

1
(17 ) 18
106 %
Cash distributions from unconsolidated investments 8
—
8
NM
Adjusted EBITDA $ 575
$ 260
$ 315
121 %

Million Megawatt Hours Generated (2)(7) 33.2
13.0
20.2
155 %
IMA for Combined Cycle Facilities (3)(7) 98 % 99 %
Average Capacity Factor for Combined Cycle Facilities (4)(7) 63 % 46 %

Average Market On-Peak Spark Spreads ($/MWh) (5):
Commonwealth Edison (NI Hub) $ 14.91
$ 12.05
$ 2.86
24 %
PJM West $ 25.58
$ 27.99
$ (2.41 ) (9 )%
North of Path 15 (NP 15) $ 14.63
$ 17.23
$ (2.60 ) (15 )%
New York—Zone A $ 29.49
$ 39.18
$ (9.69 ) (25 )%
Mass Hub $ 15.77
$ 22.30
$ (6.53 ) (29 )%
AD Hub $ 28.88
$ 34.41
$ (5.53 ) (16 )%
Average Market Off-Peak Spark Spreads ($/MWh) (5):
Commonwealth Edison (NI Hub) $ 2.97
$ (10.67 ) $ 13.64
128 %
PJM West $ 10.71
$ 2.68
$ 8.03
NM
North of Path 15 (NP 15) $ 7.75
$ 7.07
$ 0.68
10 %
New York—Zone A $ 14.12
$ 15.86
$ (1.74 ) (11 )%
Mass Hub $ 1.05
$ (2.95 ) $ 4.00
136 %
AD Hub $ 16.22
$ 11.50
$ 4.72
41 %
Average natural gas price—Henry Hub ($/MMBtu) (6) $ 2.78
$ 4.52
$ (1.74 ) (38 )%

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~~(1)~~	For the nine months ended September 30, 2015 and 2014, respectively, Other includes ($64) million and ($94) million in financial settlements, $28 million and $50 million in natural gas sales, $31 million and $28 million in ancillary services, $14 million and $11 million in tolls and $20 million and $5 million in RMR, option premiums and other miscellaneous items.


~~(2)~~	~~The nine months ended September 30, 2014 includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility which was sold on June 27, 2014.~~


~~(3)~~	IMA 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 simple average of the on- and off-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us.


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


~~(7)~~	~~Reflects the activity for the period in which the Acquisitions were included in our consolidated results.~~

Operating income for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 was ~~$290~~$120 million compared to ~~$72~~$52 million for the ~~nine~~three months ended ~~September 30, 2014.~~March 31, 2015. Adjusted EBITDA totaled ~~$575~~$212 million ~~during~~for the ~~nine~~three months ended ~~September 30, 2015~~March 31, 2016 compared to ~~$260~~$82 million ~~during~~for the ~~same period in 2014.~~three months ended March 31, 2015. The ~~$315~~$130 million increase in Adjusted EBITDA was due to $153 million from our newly acquired plants, particularly in PJM, partially offset by a $23 million decrease from our legacy plants. The decrease from our legacy plants was driven by lower energy margin, net of hedges, primarily due to ~~a positive impact related to the newly acquired plants, higher~~lower spark spreads, ~~and run times~~mainly at our ~~legacy PJM plants,~~Independence facility, driven by mild winter weather and ~~improved market capacity pricing and tolling revenues related to legacy plants,~~higher O&M costs, partially offset by higher capacity revenues.

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Outlook

Since our emergence from bankruptcy in October 2012, we have continued to reposition our fleet, primarily through acquisitions, to concentrate on the ~~expiration~~most attractive power markets while maintaining a disciplined cost structure. In 2013, our fleet capacity consisted of 65 percent MISO/CAISO resources and 35 percent PJM/ISO-NE/NYISO resources. Today our fleet is made up of 38 percent MISO/CAISO and 62 percent PJM/ISO-NE/NYISO. Upon closing the ~~ConEd contract at Independence.~~

~~Outlook~~Delta Transaction, which is expected to occur in the fourth quarter of 2016, our fleet will consist of 26 percent MISO/CAISO and 74 percent PJM/ISO-NE/ERCOT/NYISO. Additionally, our fuel mix will have transitioned to 63 percent gas and 37 percent coal versus our 2014 mix of 46 percent gas and 54 percent coal.

We expect that our future financial results will continue to be impacted by 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 the availability of our plants. 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 related to water, air and coal ash regulations. ~~Our coal fleet, primarily, may experience added costs associated with greenhouse gases (“GHG”) and the handling and disposal of coal ash.~~

~~All references to hedging within this Form 10-Q relate to economic hedging activities as we do not elect hedge accounting.~~

~~PRIDE Improvement Initiatives~~

We continue to employ our cost and performance improvement initiative, known as PRIDE, which is designed to drive recurring cash flow benefits by optimizing our cost structure, implementing company-wide process and operating improvements, and improving balance sheet efficiency. In 2013, we launched PRIDE Reloaded, with a three-year target of $135 million in operating improvements and $165 million in balance sheet efficiencies. In 2014, we exceeded our $60 million EBITDA improvement target and $65 million balance sheet efficiency target, and, subsequently accelerated our original three-year target from 2016 to by the end of 2015, a full year ahead of schedule. We are currently on track to exceed the balance sheet target for 2015 of $72 million and are expecting to achieve our EBITDA target of $45 million by year-end. In September 2015, we announced the next iteration of PRIDE which includes the newly acquired assets. “PRIDE Energized” is targeted to deliver an incremental $250 million in EBITDA and $400 million in balance sheet improvements for Dynegy over the 2016-2018 time period.

Our Operating Segments

Coal. The Coal segment is comprised of 11 ~~operating~~power generation facilities located within MISO (3,008 MW), PJM ~~(3,877~~(3,884 MW) and the ISO-NE ~~(1,493~~(1,528 MW) regions, with a total generating capacity of ~~8,378~~8,420 MW.

On ~~November 5, 2015,~~May 3, 2016, Dynegy announced ~~that it expects~~the shutdown of two units at its Baldwin power generation facility (“Baldwin”) in Baldwin, Illinois. Subject to ~~retire~~the approval of MISO, we expect to shut down the units (1,220 MW) over the next year. This decision was made after the units failed to recover their basic operating costs in the most recent MISO auction. Factors influencing these actions included a low power pricing environment, a lack of capacity revenue and significant maintenance and environmental expenditures required to appropriately maintain the facilities. Please read Note 20—Subsequent Event for further discussion.

MISO has recently approved our retirement of the final two units at the ~~465-megawatt~~465 MW Wood River Power Station in Alton, Illinois on June 1, 2016. Additionally, our Brayton Point facility is expected to be retired in ~~mid-2016, subject to~~ISO-NE in June 2017. Upon the ~~approval~~completion of ~~MISO. The decision to retire~~ the ~~Wood River facility was the result~~planned retirements and shutdowns, our Coal segment will include 5,207 MW of ~~a strategic review performed~~generation capacity, of which 1,323 MW will operate in ~~the third quarter,~~MISO and ~~was primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market that mixes out-of-state regulated generators, that receive rate based compensation~~

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~~from their home states to recover costs, with Central and Southern Illinois competitive generators that rely on the capacity market for fair compensation to recover costs.~~3,884 MW will operate in PJM.

As of ~~October~~April 19, ~~2015,~~2016, our expected remaining generation volumes, excluding Brayton Point and Wood River, are 63approximately 70 percent hedged volumetrically for ~~2015~~2016. Excluding the planned retirements and shutdowns, our generation volumes are approximately 4738 percent hedged volumetrically for ~~2016.~~2017. We plan to continue our hedging program over a one- to three-year period using various instruments, ~~which may include the sale of natural gas swaps as a cross-commodity hedge for our power revenue.~~including retail sales. Dynegy’s portfolio beyond ~~the prompt year~~2016 is primarily open to benefit from possible future power market pricing improvements. We use our retail business, Dynegy Energy Services, to hedge a portion of the output from our ~~PJM~~ facilities.

As of ~~October~~April 19, ~~2015,~~2016, excluding Brayton Point, Wood River, and the non-operated jointly-owned generating units, our expected coal requirements for ~~2015~~2016 are ~~fully~~95 percent contracted and 92 percent priced. Our forecasted coal requirements for ~~2016,~~2017, excluding the planned retirements and shutdowns, as well as the non-operated jointly-owned generating units, are 6480 percent contracted and 6172 percent priced. We look to procure and price additional fuel and transportation opportunistically. Our coal transportation requirements are fully contracted for ~~2015~~2016 and ~~2016. In addition, we~~99 percent contracted for 2017. Our coal transportation requirements are approximately 67 percent contracted for 2018 to 2020. We recently entered into a new long-term coal transportation agreement for our Kincaid facility. The contract, which begins in 2017, reflects a reduction from the 2016 rate. ~~Our coal transportation requirements are approximately 78 percent contracted for 2017 to 2019.~~

~~The Coal segment~~We cleared no volume in the MISO Planning Year 2014-2015 capacity auction and cleared 398 MW in the MISO Planning Year 2015-2016 capacity auction at $150 per MW-day.

~~On September 29, 2014,~~ We cleared no volume in the ~~Illinois Power Agency (“IPA”) issued a Request For Proposals, approved by the Illinois Commerce Commission, that included a request for~~MISO Planning Year 2016-2017 capacity ~~in Illinois for MISO Zone 4 for the 2016-2017 Planning Year. The IPA procured 1,033 MW in Zone 4 at an average price of $138.12 per MW-day. Dynegy was one of four selected suppliers.~~auction incremental to our load obligations.

In New England, our Brayton Point facility cleared 1,484 MW in the Planning Year 2014-2015 capacity auction, 1,363 MW in the Planning Year 2015-2016 capacity auction and 1,303 MW in the Planning Year 2016-2017 capacity auction. In ~~May 2017, the Brayton Point facility will be retired. In~~ New England, almost all of our capacity sales are made through ISO-NE capacity auctions.

In PJM, ~~Coal~~we cleared 3,341 MW in the Planning Year 2014-2015 capacity auction and 3,331 MW in the Planning Year 2015-2016 capacity auction. PJM introduced its new CPCapacity Performance (“CP”) product beginning with Planning Year 2016-2017. In PJM, ~~Coal~~we cleared 3,566 MW in the Planning Year 2016-2017 (1,702 MW legacy capacity and 1,864 MW CP), 3,377 MW in the Planning Year 2017-2018 (2,027 MW legacy capacity and 1,350 MW CP). Base capacity resources ~~(Base)~~(“Base”) are those capacity resources, beginning in Planning Year 2018-2019, that are not capable of sustained, predictable operation throughout the entire delivery year, but are capable of providing energy and reserves during hot weather operations. They are subject to ~~non-performance~~non-

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performance charges assessed during emergency conditions, from June through September. In PJM, ~~Coal~~we cleared 3,347 MW in the Planning Year 2018-2019 capacity auction (1,734 MW Base and 1,613 MW CP).

IPH. The IPH segment is comprised of five ~~plants,~~power generation facilities, totaling ~~4,278 MW. The Coffeen, Edwards, Duck Creek~~4,178 MW and ~~Newton facilities are located~~primarily operates in ~~the MISO region.~~MISO. Joppa, which is inwithin the Electric Energy, Inc. ~~(“EEI”)~~ control area, is interconnected to ~~MISO,~~ Tennessee Valley Authority and Louisville Gas and Electric ~~Company.~~ Company, but primarily sells its capacity and energy to MISO. We currently offer a portion of our IPH segment generating capacity into PJM. As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards and Newton facilities will have 937 MW, or 22 percent of IPH’s capacity, which is electrically tied into PJM through pseudo-tie arrangements.

On ~~September 24, 2015,~~May 3, 2016, Dynegy announced the shutdown of one of the units at its Newton power generation facility (“Newton”) in Newton, Illinois. Subject to the approval of MISO, ~~notified us that Edwards Unit 1~~we expect to shut down the unit (615 MW) this year. This decision was made after Newton failed to recover its basic operating costs in the most recent MISO auction. Factors influencing this action included a low power pricing environment, a lack of capacity revenue and significant maintenance and environmental expenditures required to appropriately maintain the facility. Upon the shutdown of the Newton unit, IPH will ~~no longer be needed~~have 3,563 MW. Please read Note 20—Subsequent Event for further discussion.

Additionally, as a ~~System Support Resource unit. Thus, MISO authorized~~result of continued weak energy prices, unsold capacity volumes, on-going required maintenance and environmental expenditures, as well as consideration of a $300 million debt maturity in 2018; we will begin a strategic review of IPH’s Genco subsidiary immediately. We intend to ~~retire Edwards Unit 1 effective January 1, 2016.~~resolve this situation by either restructuring the Genco debt to achieve a more sustainable business model or transitioning ownership to the debt holders. Please read Note 12—Debt for further discussion.

As of ~~October~~April 19, ~~2015, our IPH~~2016, IPH’s expected remaining generation volumes are approximately 6364 percent hedged volumetrically for ~~2015 and~~2016. Excluding the planned shutdown, IPH is approximately 48 percent hedged volumetrically for ~~2016.~~2017. IPH will continue to use ~~its~~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 proximity of the hedge and through participation in FTR markets. ~~We may 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 ~~October~~April 19, ~~2015,~~2016, our expected coal requirements for IPH for ~~2015~~2016 are ~~fully~~95 percent contracted and 9572 percent priced. Our forecasted coal requirements for ~~2016~~2017, excluding the planned shutdown, are 79 percent contracted and 5758 percent priced. We look to procure and price additional fuel opportunistically. Our coal transportation requirements are fully contracted for ~~2015~~2016 and ~~2016.~~2017. Our coal transportation requirements are approximately 7258 percent contracted for ~~2017~~2018 to ~~2019.~~2020.

In addition, we recently entered into a new long-term coal transportation ~~agreements~~agreement for our ~~Duck Creek and~~ Joppa ~~facilities. The rate for Duck Creek is a reduction from the 2014 rate and began in April of 2015. The new Joppa transportation contract~~facility which will begin in 2018 and ~~is also~~includes a rate reduction from the 2017 rate.

On February 24, 2016, IPM was awarded a three year capacity and energy sale contract for 959 MW with capacity revenue of $152 million. This contract supports 112 communities in Illinois represented by Good Energy, and commences on June 1, 2016.

IPH realized capacity sales in the MISO Planning Year 2014-2015 capacity auction, clearing 1,995 MW ~~all of which are expected~~ to ~~cover~~offset retail load obligations. IPH cleared 1,864 MW in the MISO Planning Year 2015-2016 capacity auction, including

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1,709 MW ~~that are expected~~ to ~~cover~~offset retail load obligations. IPH only sold 155 MW that received the $150 per MW-day clearing price. IPH cleared 1,828 MW in the MISO Planning Year 2016-2017 capacity auction to offset retail load obligations.

In PJM, ~~IPH~~we cleared no volume in the Planning Year 2014-2015 capacity auction, 301 MW in the Planning Year 2015-2016 capacity auction, 867 MW in the Planning Year 2016-2017 capacity auction (138 MW legacy capacity and 729 MW CP), 847 MW in the Planning Year 2017-2018 capacity auction (376 MW legacy capacity and 471 MW CP), and 835 MW in the Planning Year 2018-2019 capacity auction (all CP). In addition, we have also secured one segment of the transmission path required to offer an additional 240 MW of capacity and energy into PJM.

Gas. The Gas segment is comprised of 19 power generation facilities within PJM ~~(7,081~~(7,337 MW), CAISO (2,694 MW), ISO-NE ~~(2,440~~(2,429 MW) and NYISO ~~(1,108~~(1,126 MW) regions, totaling ~~13,323~~13,586 MW of electric generating capacity.

In PJM, we are installing a total of ~~260~~272 MW of ~~energy and capacity,~~uprates, which will be accomplished primarily through upgrades to the hot gas path components of our combined cycle gas turbines. The uprates ~~start~~started in the Fall of 2015 ~~at the Hanging Rock facility~~ and are expected to be completed in the Spring of ~~2017 at Liberty Electric.~~2017.

In New England, at our Lake Road and Milford facilities, we ~~have qualified~~cleared 70 MW of new uprates ~~for participation~~ in FCA-10, ~~which covers~~at a capacity rate of $7.03 per kW-month for seven years beginning with Planning Year ~~2019-2020.~~2019-2020 and extending through Planning Year 2025-2026.

In New York, ~~during 2016~~ we will be installing uprates at our Independence facility in 2016 that are expected to result in 45 MW of additional ~~energy~~summer capacity and ~~capacity at our Independence facility.~~up to 90 MW of additional winter capacity.

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Excluding volumes subject to tolling agreements, as of ~~October~~April 19, ~~2015,~~2016, our Gas portfolio is 5461 percent hedged volumetrically through ~~2015~~2016 and approximately 4122 percent hedged volumetrically for ~~2016.~~2017. As a result of the offsetting risks of our Gas and Coal segments, we are able to reduce the costs associated with hedging with third parties by executing a portion of our natural gas hedges with an affiliate. We continue to manage our remaining commodity price exposure to changing fuel and power prices in accordance with our risk management policy.

In PJM, ~~Gas~~we cleared 5,922 MW in the Planning Year 2014-2015 capacity auction, 5,996 MW in the Planning Year 2015-2016 capacity auction, 6,244 MW in Planning Year 2016-2017 (2,296 MW legacy capacity and 3,948 MW CP), 6,458 MW in Planning Year 2017-2018 (1,771 MW legacy capacity and 4,687 MW CP), and 5,708 MW in the Planning Year 2018-2019 capacity auction (all CP).

In New England, ~~Gas~~we cleared 1,890 MW in the Planning Year 2014-2015 capacity auction, 1,956 MW in the Planning Year 2015-2016 capacity auction, 1,893 MW in the Planning Year 2016-2017 capacity auction, 2,147 MW in the Planning Year 2017-2018 capacity auction, ~~and~~ 2,148 MW in the Planning Year 2018-2019 capacity auction, and 2,226 MW in the Planning Year 2019-2020 capacity auction. In New England, almost all of our capacity sales are made through ISO-NE capacity auctions.

In New York, almost 6490 percent of our Independence facility’s ~~winter~~summer capacity had been sold bilaterally prior to the most recent auction, covering the ~~Winter 2015-2016~~Summer 2016 planning period. AsIncluding bilateral and auction sales as of ~~October~~April 19, ~~2015, 939 MW of capacity was sold for the Winter 2015-2016 planning period; 697~~2016, 872 MW were sold for the Summer 2016 planning ~~period; 336~~period, 693 MW were sold for the Winter 2016-2017 planning ~~period; and 255~~period, 818 MW were sold for the Summer 2017 planning period, and 380 MW were sold for the Winter 2017-2018 planning period.

In October 2015, we contracted ~~resource adequacy~~Resources Adequacy (“RA”) capacity with Southern California Edison for Moss Landing ~~units~~Units 1 and 2 for 575 MW, 400 MW, and 850 MW, for calendar years 2017, 2018, and 2019, respectively. Our Moss Landing 6 and 7 Units have tolling and RA agreements in place that continue through December 31, 2016.

In its 2015 Gas Transmission and Storage rate case, which will set gas transportation rates for 2015-2017, Pacific Gas & Electric Company’s (“PG&E”) proposed revenue requirements and allocation proposals which, if adopted, would result in a significant increase in the rates for electric generators served by the local transmission system, including ~~Dynegy’s~~ Moss Landing Units 1 &and 2. Historically, after PG&E’s gas transportation rate structure was changed to unbundle the Backbone Transmission System (“BB”) rates, PG&E gas transmission and storage rate case settlements have included a bill credit for Moss Landing Units 1 &and 2 that effectively reduces the differential between rates for BB and local transmission system service, allowing the plant to compete against other power generators. However, according to PG&E’s own estimates, the rate differential between BB and local transmission system rates which PG&E proposes in its 2015 proceeding would result in Moss Landing Units 1 &and 2 likely experiencing a decline in dispatch hours. Dynegy is actively participating in the hearing process before the ~~California Public Utility Commission (“CPUC”)~~CPUC and is advocating positions that would maintain the ability of Moss Landing Units 1 &and 2 to compete in the California electricity ~~markets. A post-hearing~~market. Post-hearing briefing concluded in May 2015 and Oral Argument was held on October 28, 2015. A decision is expected in ~~late 2015.~~mid-2016.

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Capacity Markets

MISO. We currently have approximately ~~7,286~~7,186 MW of power generation in MISO. With the retirement of Wood River, the shutdown of two units at Baldwin and one unit at Newton and the PJM pseudo-tie arrangements that begin June 1, 2016, we will have approximately 3,949 MW in MISO. The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each Planning Year:

2013-2014 2014-2015 2015-2016
Price per MW-day $1.05 $16.75 $150.00

~~Asset~~As previously noted, we cleared no volume in the MISO Planning Year 2014-2015 capacity auction. Our Coal and IPH segments cleared 398 MW and 155 MW, respectively, in the MISO Planning Year 2015-2016 capacity auction at $150 per MW-day, incremental to our retail load obligations. Our Coal and IPH segments cleared no incremental volumes, in excess of our retail load obligations, in the MISO Planning Year 2016-2017 capacity auction.

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We have sold capacity in planning reserve auctions, incremental auctions and through bilateral transactions. Our capacity sales, aggregated by Planning Year through Planning Year 2019-2020, are as follows:



	2015-2016	2016-2017	2017-2018	2018-2019	2019-2020
Coal Segment:
Capacity sold (MW)	516	1,003	579	242	185
Average price per kW-month	$4.00	$2.75	$2.35	$2.68	$2.60
IPH Segment:
Capacity sold (MW)	2,922	2,970	2,643	2,328	470
Average price per kW-month	$2.29	$4.28	$4.54	$5.09	$5.61

A majority of the Mercury and Air Toxic Standards (“MATS”) related asset retirements ~~and confirmed future capacity exports from MISO to PJM are expected~~will conclude this year; however, we expect economic retirements to continue reducing reserve margins in MISO. MISO has a Planning Reserve Margin of 15.2 percent and has forecasted reserve margins of 16.1 percent for Planning Year 2016-2017, 16.6 percent for Planning Year 2017-2018, 16.0 percent for Planning Year 2018-2019, 15.2 percent for Planning Year 2019-2020, and 14.7 percent for Planning Year 2020-2021.

In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 ~~PRA~~Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO ~~IMM,~~(“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. ~~Dynegy~~We complied fully with the terms of the MISO ~~Tariff~~tariff in connection with the 2015-2016 PRA. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff.

On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA. The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation. ~~Please read Note 14—Commitments~~

On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and ~~Contingencies—Other Contingencies—~~Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision, which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM), are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the other arguments of the complainants regarding the 2015-2016 ~~Planning Resource Auction for further information.~~PRA and stated that those issues remain under consideration and will be addressed in a future order.

ISO-NE. We have approximately ~~3,933~~3,957 MW of power generation in ISO-NE. The most recent forward capacity auction results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each Planning Year:

2013-2014 2014-2015 2015-2016 2016-2017 2017-2018 2018-2019
Price per kW-month $2.95 $3.21 $3.43 $3.15 $7.03 $9.55



	2014-2015	2015-2016	2016-2017	2017-2018	2018-2019	2019-2020
Price per kW-month	$3.21	$3.43	$3.15	$7.03	$9.55	$7.03

The forecasted ~~2015~~2016 ISO-NE reserve margin is ~~22.8~~25.2 percent versus a target reserve margin of ~~13.9~~15.6 percent. On February 2, 2015, ISO-NE conducted the capacity auction for Planning Year 2018-2019 (FCA-9). Rest-of-Pool, which includes most of our facilities, cleared at a price of $9.55 per kW-month. The Southeastern Massachusetts and Rhode Island (“SEMA/RI”) zone, where our recently acquired Dighton facility is located, had insufficient supply to satisfy its capacity requirements. As a result, the zone separated from Rest-of-Pool, with existing resources in the zone receiving the Net Cost of New Entry (“Net CONE”) price of $11.08 per kW-month and new resources in the zone receiving the auction starting price of $17.73 per kW-month. In the most recentEffective for this auction, a downward sloping demand curve replaced the vertical demand curve and the system-wide administrative pricing rules. Performance incentive rules also went into effect for Planning Year 2018-2019, having the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level. Rest-of-Pool, which includes most of our facilities, cleared at a price of $9.55 per kW-month. The Southeastern Massachusetts and Rhode Island zone, where our recently acquired Dighton facility is located, had insufficient supply to satisfy its capacity

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requirements. As a result, the zone separated from Rest-of-Pool, with existing resources in the zone receiving the Net Cost of New Entry price of $11.08 per kW-month and new resources in the zone receiving the auction starting price of $17.73 per kW-month. On February 8, 2016, ISO-NE conducted the capacity auction for Planning Year 2019-2020 (FCA-10). In this auction, Rest-of-Pool cleared at $7.03 per kW-month.

We have sold capacity in FCAs, supplemental auctions and through bilateral transactions. Our capacity sales, aggregated by Planning Year through Planning Year 2019-2020, are as follows:



	2015-2016	2016-2017	2017-2018	2018-2019	2019-2020
Capacity sold (MW)	3,738	3,663	2,181	2,148	2,240
Average price per kW-month	$3.31	$3.25	$6.99	$9.66	$7.03

PJM. We currently have approximately ~~10,958~~11,221 MW of power generation in PJM. ~~Gas-fired~~With the expected PJM pseudo-tie arrangements from the IPH fleet beginning June 1, 2016, we will have approximately 12,158 MW of power generation in PJM. Our plants within PJM are mixed between Eastern Mid-Atlantic Area Council (“EMAAC”) (Liberty), Mid-Atlantic Area Council (“MAAC”) (Ontelaunee), Commonwealth Edison (“COMED”) (Elwood, Kendall, ~~Lee)~~Lee, and Kincaid), American Transmission Service, Inc. (“ATSI”) (Richland/Stryker), and Regional Transmission Organization (“RTO”) (balance of plants). PJM has begun the transition of the PJM capacity market to CP product. On August 26-27, 2015, PJM held a transitional auction to convert up to 60 percent of PJM’s capacity needs for Planning Year 2016-2017 from legacy capacity to CP. On September 3-4, 2015, PJM held a transitional auction to convert 70 percent of PJM’s capacity needs for Planning Year 2017-2018 from legacy capacity to CP. On August 10-14, 2015, PJM held the ~~BRA~~Base Residual Auction to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2018-2019. PJM will procure 100 percent

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CP for all resources beginning with Planning Year 2020-2021. The most recent Reliability Pricing Model ~~(“RPM”)~~ auction results for PJM’s RTO and MAAC zones, in which our assets are located, are as follows for each Planning Year:



	2014-2015		2015-2016		2016-2017				2017-2018				2018-2019
	Legacy Capacity		Legacy Capacity		Legacy Capacity		CP		Legacy Capacity		CP		Base		CP
RTO zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77
MAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77
EMAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	210.63	$	225.42
COMED zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	200.21	$	215.00
ATSI zone, price per MW-day	$	125.99	$	357.00	$	114.23	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77

We have sold capacity in base residual auctions, incremental auctions, transitional auctions, and through bilateral transactions. Our capacity sales, aggregated by Planning Year and capacity type through Planning Year 2018-2019, are as follows:



	2015-2016	2016-2017	2017-2018	2018-2019
Capacity sold (MW)	9,349	9,601	9,822	9,729
Average price per MW-day	$146.53	$120.30	$139.58	$180.36

NYISO. We have approximately ~~1,108~~1,126 MW of power generation in NYISO. The ~~forecasted 2015 NYISO reserve margin is 24.7 percent versus a target reserve margin of 17 percent. The~~ most recent seasonal auction results for NYISO's Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:

Winter 2013-2014 Summer 2014 Winter 2014-2015 Summer 2015 Winter 2015-2016 Summer 2016 Winter 2016-2017 Summer 2017
Price per kW-month $2.58 $5.15 $2.90 $3.50 $2.30 $3.48 $2.25 $2.87



	Winter 2014-2015	Summer 2015	Winter 2015-2016	Summer 2016
Price per kW-month	$2.90	$3.50	$1.25	$3.62

We have sold capacity in seasonal strip auctions, supplemental auctions, and through bilateral transactions. Our capacity sales, aggregated by season through Summer 2019, are as follows:



	Winter 2015-2016	Summer 2016	Winter 2016-2017	Summer 2017	Winter 2017-2018	Summer 2018	Winter 2018-2019	Summer 2019
Capacity sold (MW)	1,124	872	693	818	380	340	185	125
Average price per kW-month	$2.19	$3.38	$2.57	$3.40	$3.10	$3.31	$3.13	$3.20

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CAISO. We have approximately 2,694 MW of power generation in CAISO. The CAISO capacity market is a bilateral market in which Load Serving Entities are required to procure sufficient resources to meet their peak load plus a 15 percent reserve margin. We transact with ~~Investor Owned Utilities, Municipalities, Community Choice Aggregators,~~investor owned utilities, municipalities, community choice aggregators, retail providers, and other marketers through Request for Offers ~~(“RFO”)~~ solicitations, broker markets, and directly with bilateral ~~transactions. We transact~~transactions for both the ~~standard RA capacity as well as flexible~~Standard and Flexible RA capacity. ~~Although~~Beginning on or after May 1, 2016, CAISO is expected to implement the ~~CPUC created~~voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the ~~new flexible~~market. This Competitive Solicitation Process will replace the existing pricing mechanism for CPM and will provide another avenue to sell RA ~~capacity market~~capacity. Like CPM, we expect this mechanism to ~~address the risk of retirement of flexible gas-fired~~be used infrequently because generation ~~demand for this product is low due to~~supply has been ample, ~~supply of generation. In addition, growth for energy~~and demand has been stagnant, mainly due to energy efficiency programs and distributed generation of residential and commercial rooftop solar.

Our capacity sales, aggregated by calendar year for the remainder of 2016 through 2019 for Moss Landing Units 1 and 2, are as follows:



	Remainder of 2016	2017	2018	2019
Capacity sold (MW)	245	725	400	850

Other Market Developments

On ~~May 23, 2014,~~January 25, 2016, the U.S. Supreme Court overturned the decision of the U.S. Court of Appeals for the District of Columbia Circuit (“D.C. Circuit”) ~~vacated~~and affirmed FERC’s jurisdiction over compensation to Demand Response providers in wholesale competitive markets and the compensation method as proscribed in FERC Order No. ~~745, which provides compensation for demand response resources that participate~~745. The decision effectively maintains the status-quo with respect to Demand Response participation in the ~~energy~~wholesale markets, ~~administered by~~ because the ISOs/RTOs and ISOs. FERC requested a review of this decision on July 7, 2014, and the court denied the request on September 17, 2014. On October 20, 2014, the D.C. Circuit granted FERC’s motion for a stay of the mandate, pending the deadline for filing of a petition for writ of certiorari with the U.S. Supreme Court. On January 15, 2015, two petitions were filed with the U.S. Supreme Court seeking review of the D.C. Circuit’s decision inrefrained from making changes to market design while the case ~~one by FERC and one by private parties who intervened in the court of appeals in support of FERC. On May 4, 2015, the U.S. Supreme Court granted the petitions. Oral argument~~ was held on October 14, 2015, with a decision likely by mid-2016. PJM has announced its intent to include demand response in its next base residual capacity auction, as modified by the PJM CP Proposal accepted by FERC. Under PJM’s plan, existing demand response resources that cannot meet CP requirements (unlimited interruptions on an annual basis) will be allowed into the Base Capacity Product until Planning Year 2020-2021, where they will be phased out, leaving only CP demand response. Each of the other ISO/RTOs is evaluating options for complying with the decision, but it is unclear how Demand Response will participate in the energy, ancillary service and capacity markets, and therefore, it is too early to evaluate market impacts at this time.pending.

Environmental and Regulatory Matters

Please read Item 1. Business-Environmental Matters in our Form 10-K ~~and Item 2. Results of Operations-Outlook-Environmental and Regulatory Matters in our Forms 10-Q~~ for ~~the periods ended March 31, 2015 and June 30, 2015 for~~a detailed ~~discussions~~discussion of our environmental and regulatory matters.

The Clean Air Act

~~National Ambient~~Mercury and Air ~~Quality Standards (“NAAQS”).~~Toxic Standards. ~~On October 1, 2015,~~In April 2016, the EPA issued a final finding that consideration of cost does not change the Agency’s determination that regulation of HAP emissions from coal- and oil-fired EGUs is appropriate and necessary under CAA section 112. Numerous states have petitioned for Supreme Court review of the D.C. Circuit’s decision remanding the MATS rule ~~lowering the primary and secondary NAAQS for ground-level ozone from 75~~without vacating to ~~70 parts per billion (ppb).~~ consider cost.

In ~~accordance with the CAA,~~March 2016, the EPA ~~anticipates designating attainment~~finalized corrections to its November 2014 MATS rule revisions addressing startup and nonattainment areas for the 2015 ozone NAAQS by October 1, 2017. State implementation plans for the 2015 ozone NAAQS generally would be due in 2020-2021. Based on the severity of nonattainment designation, nonattainment areas would be required to achieve compliance between 2020 and 2037. The nature and scope of potential future requirements concerning the 2015 ozone NAAQS cannot be predicted with confidence at this time.

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~~In August 2015, the EPA issued a final rule regarding the 2010 one-hour SO~~₂ ~~NAAQS that requires air agencies to characterize air quality around sources that emit 2,000 tons per year or more of SO~~₂ ~~using either ambient air quality measured at monitors or modeling of source emissions. The rule requires air agencies to identify, by July 2016, sources with SO~~₂ emissions above 2,000 tons per year. For source areas that will be evaluated through air quality modeling, the modeling analysis must be submitted to the EPA by January 2017. For source areas that will be evaluated through air qualityshutdown monitoring ~~air quality data will be collected for years 2017 through 2019. The rule will lead to the development of data that informs attainment and nonattainment area designations for the 2010 one-hour SO~~₂ ~~NAAQS that are required by a court order to occur over the period July 2016 through December 2020. The EPA anticipates making final designations for the majority~~instrumentation. With adoption of the country by December 2017, except for areas with new monitoring networks that begin operation in 2017 for which final designations would be made by December 2020. For areas designated nonattainment in 2017, the EPA anticipates state implementation plans (SIPs) would be due in August 2019. For areas designated nonattainment in 2020, the EPA anticipates SIPs would be due in August 2022. Areas designated nonattainment must achieve attainmentcorrections, our startup and shutdown instrumentation extension requests are no ~~later than five years after designation.~~

~~The nature and scope of potential future requirements concerning the 2015 ozone NAAQS and 2010 one-hour SO~~₂~~NAAQS cannot be predicted with confidence at this time. A future requirement for additional emission reductions of NOx or SO~~₂ ~~at any of our coal-fired generating facilities for purposes of the 2015 ozone NAAQS or 2010 one-hour SO~~₂ ~~NAAQS may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.~~longer needed.

The Clean Water Act

Effluent Limitation Guidelines (“ELG”). On September 30, 2015, the EPA issued a final rule revising the ELG for steam electric power generation units. The ELG final rule establishes new or additional requirements for wastewater streams associated with steam electric power generation processes and byproducts, including flue gas desulfurization, fly ash, bottom ash and flue gas mercury control. For EGUs greater than 50 MW, the final rule establishes a zero discharge standard for bottom ash transport water, fly ash transport water and flue gas mercury control wastewater. The rule also establishes effluent limits for flue gas desulfurization wastewaters based on chemical precipitation and biological treatment. Existing EGUs are required to comply with the discharge limits in the ELG final rule by a date determined by the permitting authority that is as soon as possible beginning November 1, 2018, but no later than December 31, 2023.

We ~~are currently evaluating~~have evaluated the ELG final rule and the ~~CCR~~Coal Combustion Residuals (“CCR”) rule ~~to determine whether~~in light of our current management of CCR, including beneficial ~~reuse, and~~reuse. At this time, we estimate the ~~use~~cost of the CCR surface impoundments should be altered. We are also evaluating the potential costs to comply with these regulations, which could be material. The ELG final rule’s zero discharge standard on bottom ash transport water on all units greater than 50 MW may add material compliance costs to our ~~previously disclosed preliminary cost estimate of approximately $288 million for~~ compliance with the ELG rule ~~which we are currently reviewing.~~to be approximately $290 million to $350 million. The majority of ELG compliance ~~spend is~~expenditures are expected to occur in the ~~2018-2023~~2016-2023 timeframe. ~~Our~~

Cooling Water Intake Structures. At this time, we estimate ~~and timing could change significantly depending upon a variety~~the cost of ~~factors, including detailed site-specific engineering analyses, the outcome of potential litigation concerning the ELG final rule, and~~ our ~~final~~ compliance ~~plans~~ with the ~~EPA’s CCR rule.~~

~~Waters~~cooling water intake structure rule will be approximately $17 million, with the majority of spend in the 2020-2023 timeframe. This estimate excludes Moss Landing, where we preliminarily estimate the cost of our compliance under the provisions of the ~~United States.~~settlement agreement with the California State Water Resources Control Board to be approximately $10 million in aggregate through 2020.

Coal Combustion Residuals

EPA CCR Rule. ~~In October 2015,~~At this time, we estimate the ~~U.S. Court~~cost of ~~Appeals for~~our compliance will be approximately $210 million to $260 million with the ~~Sixth Circuit issued an order staying the EPA and the U.S. Army Corps of Engineers’ final rule defining the term “waters~~majority of the ~~United States” pending~~expenditures in the 2016-2023 timeframe. This estimate is reflected in our asset retirement obligations (“AROs”).

Illinois CCR Rule.The IPCB extended its stay of the Illinois EPA’s proposed rulemaking to June 2016.

Coal Segment Groundwater. Please read Note 13—Commitments and Contingencies, Other Contingencies, Coal Segment Groundwater, for further ~~review by~~discussion.

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Asset Retirement Obligations

AROs are recorded as liabilities on our unaudited consolidated balance sheets at their Net Present Value (“NPV”) using interest rates ranging from 8.8 percent to 19.4 percent.The following table presents the ~~court.~~NPV and projected obligation as of March 31, 2016:



			Projected Obligation by Period
(amounts in millions)	NPV		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years		Total
Coal
CCR	$	120	$	32	$	38	$	32	$	39	$	141
Non-CCR	55		—		17		5		112		134
Total Coal segment	175		32		55		37		151		275

Gas
Non-CCR	29		15		3		—		45		63
Total Gas segment	29		15		3		—		45		63

IPH
CCR	69		—		89		21		—		110
Non-CCR	12		5		4		27		76		112
Total IPH segment	81		5		93		48		76		222
Total Consolidated AROs	$	285	$	52	$	151	$	85	$	272	$	560

Coal Segment. At March 31, 2016, Coal segment CCR AROs consisted of projected expenditures of $141 million related to surface impoundments and groundwater monitoring. Non-CCR AROs consisted of projected expenditures of $96 million related to asbestos removal, $30 million related to surface impoundments and groundwater monitoring, and $8 million related to landfill closures.

Gas Segment. At March 31, 2016, Gas segment Non-CCR AROs consisted of projected expenditures of $37 million related to decommissioning, $11 million related to the South Bay demolition, $5 million related to asbestos removal, $4 million related to pipeline burial/removal, and $6 million related to other obligations.

IPH Segment. At March 31, 2016, IPH segment CCR AROs consisted of projected expenditures of $110 million related to surface impoundments and groundwater monitoring. Non-CCR AROs consisted of projected expenditures of $71 million related to asbestos removal, $30 million related to surface impoundments and groundwater monitoring, and $11 million related to landfill closures.

Climate Change

~~Federal Regulation of Greenhouse Gases.~~ On October 22, 2015, numerous states, industry associations and labor groups filed lawsuits challenging the EPA’s final rule Clean Power Plan. Numerous parties challenging the rule also filed motions to stay the rule pending completion of judicial review.

~~We are analyzing the EPA’s final rules to reduce EGU CO~~₂ ~~emissions, the potential impacts on our power generation facilities, and how the rules intersect with electricity market design. The nature and scope of CO~~₂ ~~emission reduction requirements that ultimately may be imposed on our facilities as a result of the EPA’s EGU CO~~₂ reduction rules are uncertain at this time, but may result in significantly increased compliance costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

State Regulation of Greenhouse ~~Gases.~~Gas (“GHG”)

California. The California Air Resources Board (“CARB”) and the Province of Québec held their ~~fourth~~sixth joint allowance auction in ~~August 2015~~February 2016 with current vintage auction allowances selling at a clearing price of ~~$12.52~~$12.73 per metric ton and ~~2018~~2019 auction allowances selling at a clearing price of ~~$12.30~~$12.73 per metric ton. The CARB expects allowance prices to be in the $15 to $30 range by 2020. We have participated in quarterly auctions or in secondary markets, as appropriate, to secure allowances for our affected assets. The next quarterly auction is scheduled for ~~November 2015.~~May 2016.

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We estimate the cost of GHG allowances required to operate ~~our units~~Moss Landing Units 1 and 2 in California during ~~2015~~2016 will be approximately ~~$16~~$14 million; however, 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. ~~Due to the~~The tolling agreement for Moss Landing Units 6 and 7 ~~under which~~provides that our counterparty is financially responsible for GHG ~~allowance costs are passed through to the tolling counterparty, we expect only to acquire~~ allowances ~~covering the GHG emissions of Moss Landing Units 1 and 2.~~for these units.

RGGI. In ~~September 2015,~~March 2016, RGGI held its ~~twenty-ninth~~thirty-first auction, in which approximately ~~25.4~~15 million allowances were sold at a clearing price of ~~$6.02~~$5.25 per allowance. RGGI’s next quarterly auction is scheduled for ~~December 2015.~~June 2016. We have participated in quarterly RGGI auctions or in secondary markets, as appropriate, to secure allowances for our affected assets.

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We estimate the cost of RGGI allowances required to operate our affected facilities in Connecticut, Maine, Massachusetts, and New York during ~~2015~~2016 will be approximately ~~$64~~$45 million. ~~While~~We expect any future changes in the ~~cost~~price of RGGI allowances ~~required~~ to ~~operate our RGGI-affected facilities is expected to increase in future years, we expect that the cost of compliance would~~ be reflected in both the forward and locational marginal prices for power ~~market,~~ and ~~the actual impact~~be neutral to our gross ~~margin would be largely offset by an increase in revenue.~~margins.

RISK MANAGEMENT DISCLOSURES

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


(amounts in millions)	As of and for the Nine Months Ended September 30, 2015			As of and for the Three Months Ended March 31, 2016
Fair value of portfolio at December 31, 2014	$	(83	)
Fair value of portfolio at December 31, 2015				$	(90	)
Risk management gains recognized through the statement of operations in the period, net	62			91
Contracts realized or otherwise settled during the period	55			18
Acquisitions	(235		)
Changes in collateral/margin netting	89			(27		)
Fair value of portfolio at September 30, 2015	$	(112	)
Fair value of portfolio at March 31, 2016				$	(8	)

The net risk management liability of ~~$112~~$8 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 ~~September 30, 2015~~March 31, 2016, based on our valuation methodology:

Net Fair Value of Risk Management Portfolio


(amounts in millions)	Total			2015			2016			2017			2018			2019			Thereafter			Total			2016			2017			2018			2019			2020			Thereafter
Market quotations (1)(2)	$	(148	)	$	(41	)	$	(77	)	$	(18	)	$	(8	)	$	(3	)	$	(1	)	$	(53	)	$	9		$	(46	)	$	(9	)	$	(6	)	$	(1	)	$	—
Prices based on models (2)	(62		)	(4		)	(10		)	(40		)	(10		)	1			1			(34		)	(24		)	(4		)	(8		)	1			1			—
Total (3)	$	(210	)	$	(45	)	$	(87	)	$	(58	)	$	(18	)	$	(2	)	$	—		$	(87	)	$	(15	)	$	(50	)	$	(17	)	$	(5	)	$	—		$	—

(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 5—Risk Management Activities, Derivatives, and Financial Instruments for further discussion.


(3)	Excludes ~~$98~~$79 million of broker margin that has been netted against Risk ~~Management~~management liabilities on our unaudited consolidated balance sheets. Please read Note 5—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 expect, believe, or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment of the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties, and other

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factors that could cause our actual results and financial position to differ materially from those contemplated by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate,” “estimate,” “project,” “forecast,” “plan,” “may,” “will,” “should,” ~~“expect”~~“expect,” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:

beliefs and assumptions about weather and general economic conditions;

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 power market prices, if any;

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

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

the effects of, or changes to, MISO, PJM, CAISO, NYISO, or ISO-NE power and capacity procurement processes;

expectations regarding, or impacts of, 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 that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect;

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

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

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

our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and new performance incentives in ISO-NE;

our ability to optimize our assets through targeted investment in cost effective technology enhancements;

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;

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

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

expectations regarding performance standards and capital and maintenance expenditures;

beliefs concerning the strategic review of Genco, including any debt restructuring;

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

~~expectations regarding the synergies and anticipated benefits of the Acquisitions;~~

~~beliefs concerning our capital allocation program, including the amount of shares, manner, timing and funding of the share repurchase program;~~

anticipated timing, ~~outcomes~~outcome, and ~~impacts~~impact of the expected ~~retirements~~retirement of Brayton Point ~~Edwards Unit~~and the shutdown of Baldwin Units 1 and ~~Wood River;~~3 and Newton Unit 2;

beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion ~~facility~~and Wood River facilities and any potential future remediation obligations at the South Bay facility;

expectations regarding the financing, synergies, completion, timing, terms, and anticipated benefits of the Delta Transaction; and

beliefs regarding redevelopment efforts for the Morro Bay facility.

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, except as noted below.~~10-K.

~~Goodwill~~

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We record goodwill when the purchase price for an acquisition exceeds the estimated net fair value of the identified tangible and intangible assets acquired. We allocate goodwill to our reporting units based on the relative fair value of the purchased operating assets assigned to our existing reporting units.

We perform an annual impairment assessment in the fourth quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less than its carrying value.

For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the first step of the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value inclusive of goodwill. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we must perform the second step of the goodwill impairment test to determine the implied fair value of the reporting unit’s goodwill. If we determine during the second step that the carrying value of a reporting unit’s goodwill exceeds its implied fair value, we record an impairment loss equal to the difference.

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 ~~September 30, 2015~~March 31, 2016.

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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 VaR ~~and average VaR~~ at ~~September 30, 2015~~March 31, 2016 compared to December 31, ~~2014 were~~2015 was lower due to a decrease in volatility and price.

Daily and Average VaR for Risk Management Portfolios


(amounts in millions)	September 30, 2015		December 31, 2014		March 31, 2016		December 31, 2015
One day VaR—95 percent confidence level	$	7	$	10	$	9	$	20
One day VaR—99 percent confidence level	$	9	$	14	$	13	$	29
Average VaR—95 percent confidence level for the rolling twelve months ended	$	7	$	8	$	10	$	8

Credit Risk. The following table represents our credit exposure at ~~September 30, 2015~~March 31, 2016 associated with the mark-to-market portion of our risk management portfolio, on a net basis. We had exposure of less than $1 million related to non-investment grade quality counterparties.

Credit Exposure Summary


(amounts in millions)	Investment Grade Quality		Non-Investment Grade Quality		Total		Investment Grade Quality
Type of Business:
Financial institutions	$	29	$	—	$	29	$	71
Oil and gas producers	—		—		—		4
Utility and power generators	19		—		19		21
Commercial/industrial/end users							2
Total	$	48	$	—	$	48	$	98

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.

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The absolute notional amounts associated with our interest rate contracts were as follows at ~~September 30, 2015~~March 31, 2016 and December 31, ~~2014~~2015, respectively:


	September 30, 2015			December 31, 2014			March 31, 2016			December 31, 2015
Interest rate swaps (in millions of U.S. dollars)	$	779		$	785		$	775		$	777
Fixed interest rate paid (percent)	3.19		%	3.19		%	3.19		%	3.19		%

Item 4—CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of our management, including our Chief Executive Officer (“CEO”) and our Chief Financial Officer (“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 ~~September 30, 2015~~March 31, 2016.

Changes in Internal Controls Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the quarter ended ~~September 30, 2015~~March 31, 2016.

8161

PART II. OTHER INFORMATION

Item 1—LEGAL PROCEEDINGS

Please read Note ~~14—~~13—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 below and Item 1A—Risk Factors of our Form 10-K for factors, risks, and uncertainties that may affect future results.

~~Item 2—UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS~~We may be unable to obtain the regulatory approvals required to complete the Delta Transaction or, in order to do so, we may be required to comply with material restrictions on our conduct or satisfy other material conditions required by various regulatory authorities.

Consummation of the Delta Transaction is subject to conditions and governmental approvals, including approval from the FERC and the Public Utility Commission of Texas and the expiration or termination of the waiting period applicable to the Delta Transaction under the Hart-Scott-Rodino Antitrust Improvements (“HSR”) Act. The closing of the Delta Transaction is also subject to the condition that there be no injunction or order issued by a governmental authority that restrains, enjoins, or otherwise prohibits the consummation of the transactions contemplated by the Delta Stock Purchase Agreement. The waiting period applicable to the Delta Transaction under the HSR Act has been terminated, but we can provide no assurance that all other required regulatory approvals will be obtained. There can also be no assurance as to the cost, scope, or impact of the actions that may be required to obtain the required regulatory approvals. Furthermore, these actions could have the effect of delaying or preventing completion of the Delta Transaction or imposing additional costs, conditions, or restrictions on our business and operations, some of which could be material and adversely affect our revenues and profitability following the consummation of the transaction.

Furthermore, the FERC, the Public Utility Commission of Texas, the Department of Justice, or other governmental authorities could seek to block or challenge the Delta Transaction as they deem necessary or desirable in the public interest at any time, including after completion of the transaction. In addition, in some circumstances, a competitor, customer, or other third party could initiate a private action under antitrust laws challenging or seeking to enjoin the Delta Transaction, before or after it is consummated. We may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

If the Delta Transaction is consummated, we may be unable to successfully integrate the operations of the assets with our existing operations or to realize targeted cost savings, revenues and other anticipated benefits of the transaction.

The success of the Delta Transaction will depend, in part, on our ability to realize the anticipated benefits and synergies from integrating GSENA’s assets with our existing generation business. To realize these anticipated benefits, the businesses must be successfully combined.

We may be required to make unanticipated capital expenditures or investments in order to maintain, integrate, improve or sustain the assets’ operations, or take unexpected write-offs or impairment charges resulting from the transaction. Further, we may be subject to unanticipated or unknown liabilities relating to the assets. If any of these factors occur or limit our ability to integrate the businesses successfully or on a timely basis, the expectations of our future financial conditions and results of operations following ~~table sets forth certain~~the transaction might not be met.

In addition, we and GSENA have operated and, until the consummation of the transaction, will continue to operate independently. It is possible that the integration process could result in the loss of key employees, the disruption of each company’s ongoing businesses, inefficiencies, or inconsistencies in standards, controls, information technology systems, procedures, and policies, any of which could adversely affect our ability to achieve the anticipated benefits of the transaction and could harm our financial performance. Further, we may be required to implement or improve the internal controls, procedures, and policies of the assets to meet standards applicable to U.S. public companies, which may be time-consuming and more expensive than anticipated.

In addition, we continue to evaluate our estimates of synergies to be realized from, and the fair value accounting allocations associated with, ~~respect~~the Delta Transaction and refine them. Accordingly, actual cost-savings, the costs required to ~~repurchases~~realize the cost-savings, and the source of the cost-savings could differ materially from our estimates, and we cannot assure you that we will achieve the full amount of cost-savings on the schedule anticipated or at all.

Finally, we may not be able to achieve the targeted operating or long-term strategic benefits of the Delta Transaction. If the combined businesses are not able to achieve our objectives, or are not able to achieve our objectives on a timely basis, the anticipated benefits of the transaction may not be realized fully or at all. An inability to realize the full extent of, or any of, the

Table of Contents

anticipated benefits of the transaction, as well as any delays encountered in the integration process, could have an adverse effect on our financial condition, results of operations, and cash flows.

We will incur significant transaction and acquisition-related costs in connection with the Delta Transaction.

We expect to incur significant costs associated with the Delta Transaction and combining the operations of our company with GSENA, including costs to achieve targeted cost-savings. The substantial majority of the expenses resulting from the transaction will be composed of transaction costs, systems consolidation costs, and business integration and employment-related costs, including costs for severance, retention, and other restructuring. We may also incur transaction fees and costs related to formulating integration plans. Additional unanticipated costs may be incurred in the integration of our and the GSENA businesses. Although we expect that the elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of the businesses, should allow us to offset incremental transaction and acquisition-related costs over time, this net benefit may not be achieved in the near term, or at all.

Failure to consummate the Delta Transaction could negatively impact the market price of our common stock ~~during~~and cause us to incur significant costs that could materially impact our financial performance, results of operations, or financial condition.

There can be no assurance that the ~~quarter ended September 30, 2015.~~Delta Transaction will be consummated. Failure to consummate the Delta Transaction may negatively impact the future trading price of our common stock, and if the Delta Transaction is not consummated, the market price of our common stock may decline to the extent that the current market price of our common stock reflects a market assumption that there is a high probability that the Delta Transaction will be consummated. In addition, if the Delta Stock Purchase Agreement is terminated under certain circumstances, the Delta Stock Purchase Agreement requires the Purchaser to pay GSENA a fee of $132 million, of which we would be obligated to fund $85.8 million. Payment of such termination fee could materially and adversely impact our results of operations or financial condition.

The announcement and pendency of the acquisitions could impact or cause disruptions in our and GSENA’s operations.

The announcement and pendency of the Delta Transaction could impact or cause disruptions in our, and GSENA’s operations. Specifically:

our and GSENA’s current and prospective customers and suppliers may experience uncertainty associated with the transaction, including with respect to current or future business relationships with us and GSENA or the combined company business and may attempt to negotiate changes in existing business;

our and GSENA’s employees may experience uncertainty about their future roles with us, which may adversely affect our and GSENA’s ability to retain and hire key employees; and

the transaction may give rise to potential liabilities, including potential stockholder lawsuits relating to the transaction.

Any of the above disruptions could have an adverse effect on our business, results of operations, and financial condition.

If the Delta Transaction is consummated, we will conduct a portion of our operations through a joint venture, which will subject these operations to additional risks that could have a material adverse effect on their success and on our financial position and results of operations.

If the Delta Transaction is consummated, we will conduct a portion of our operations through Atlas Power, a joint venture with the ECP Funds. The Atlas Power joint venture arrangement may present financial, managerial, and operational challenges, including potential disputes, liabilities, and contingencies, and may involve risks not otherwise present when operating assets directly, including, for example:

our joint venture partner may have business interests or goals that are or may become inconsistent with our business interests or goals;

our joint venture partner shares certain approval rights over major decisions;

we may be unable in certain circumstances to control the amount of cash we will receive from Atlas Power;

we may incur liabilities as a result of an action taken by Atlas Power or our joint venture partner;

we may be required to devote significant management time to the requirements of and matters relating to Atlas Power; and

disputes between us and our joint venture partner may result in delays, litigation or operational impasses.

The challenges and risks described above could adversely affect Atlas Power’s ability to transact its business, which would in turn negatively affect Atlas Power’s financial condition, results of operations, and distributable cash flows. Any such negative effects could have an adverse effect on our financial condition and results of operations.

Table of Contents

Period
(a)
Total Number of Shares Purchased

(b)
Average
Price Paid
per Share

(c)
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)

(d)
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31 —
$ —
—
$ —
August 1 - August 31 4,996,299
$ 25.37
4,996,299
$ 123,000,000
September 1 - September 30 —
$ —
—
$ —
Total 4,996,299
$ 25.37
4,996,299
$ 123,000,000


~~(1)~~	On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million, initiated in the third quarter of 2015, with targeted completion in 2016. The shares will be purchased in the open market or privately negotiated transactions from time to time at management’s discretion at prevailing market prices.

If the Delta Transaction is consummated, Atlas Power will be financed primarily through non-recourse project finance debt. If Atlas Power defaults on its obligations under such non-recourse debt, we may decide to make certain payments to the relevant debt holders to prevent foreclosure, which would, without such payments, cause us to lose our ownership interest in Atlas Power or in some or all of its power generation facilities.

82If the Delta Transaction is consummated, Atlas Power will be financed primarily through non-recourse project finance debt. Non-recourse project finance debt refers to financing arrangements that are repaid solely from the project’s revenues and are secured by the project’s physical assets, major contracts, cash accounts, and, in many cases, the project owners’ ownership interests in the project. If Atlas Power defaults on its obligations under its non-recourse financing agreements, we may decide to make payments to prevent the debt holders from foreclosing on Atlas Power’s collateral. Such a foreclosure would result in our losing our ownership interests or in some or all of its power generation facilities. The loss of our ownership interests, or some or all of its assets, or our decision to make payments to lenders to avoid any such loss, could have a material adverse effect on our business, financial condition, and results of operations.

If the PIPE Transaction is consummated, Terawatt will own approximately 15% of our common stock and may exert influence over matters requiring Board of Directors and/or stockholder approval.

If the PIPE Transaction is consummated, Terawatt will beneficially own approximately 15% of the outstanding shares of our common stock and will have the right to appoint one member to our Board of Directors. As a result, Terawatt may be able to exercise influence over matters requiring approval by our Board of Directors and our stockholders.

The interests of Terawatt may conflict with the interests of our other stockholders. Terawatt may have an interest in having us pursue, or not pursue, acquisitions, divestitures, and other transactions that, in its judgment, could enhance its investment in us, even though such transactions might involve benefits or risks to other stockholders.

In addition, Terawatt and its affiliates engage in a broad spectrum of activities, including investments in the power generation industry. In the ordinary course of their business activities, Terawatt and its affiliates may engage in activities where their interests conflict with our interests or those of our stockholders. Further, Dynegy has agreed to renounce any interest in a corporate or business opportunity taken by Terawatt or its affiliates, unless such corporate or business opportunity is offered to the member of our Board of Directors appointed by Terawatt in his or her capacity as a director of Dynegy.

Item 6—EXHIBITS

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



Exhibit Number		Description

**4.12.1	Fifth Supplemental Indenture to the 2019 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors, (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor.
**4.2	Fifth Supplemental Indenture to the 2022 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor.
**4.3	~~Fifth Supplemental Indenture~~Stock Purchase Agreement, dated February 24, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.* (incorporated by reference to Exhibit 2.1 to the ~~2024 Notes Indenture, dated September 21, 2015, among~~Current Report on Form 8-K of Dynegy Inc.~~, the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association, as trustee, adding Dynegy Resource Holdings, LLC as a guarantor.~~ filed on March 1, 2016 File No. 001-33443).
**~~4.4~~2.2		First Amendment Stock Purchase Agreement, dated May 2, 2016, by and between Atlas Power Finance, LLC, GDF SUEZ Energy North America, Inc. and International Power, S.A.*.
10.1		Fifth Supplemental Indenture to the 2023 Notes Indenture, dated September 21, 2015, among Dynegy Inc., the Subsidiary Guarantors (as defined therein) and Wilmington Trust, National Association as Trustee, adding Dynegy Resource Holdings, LLC as a guarantor.
**10.1	~~Amendment to Non-Qualified Stock Option~~Form of Performance Award Agreement ~~- Flexon (2015 Employment Agreement Award).~~
**10.2	~~Amendment No. 2 to Letter of Credit and Reimbursement Agreement by and between Illinois Power Marketing Company ad Union Bank, N.A.~~
~~10.3~~	~~Form of Dynegy Inc. Executive Participation Agreement~~(2016 Awards) (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on ~~October 30, 2015~~March 14, 2016 File No. 001-33443).
~~10.4~~10.2		~~Dynegy Inc. Severance Plan~~Form of Performance Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on ~~October 30, 2015~~March 14, 2016 File No. 001-33443).
10.3		Form of Stock Unit Award Agreement (Executive Management) (2016 Awards) (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).
10.4		Form of Stock Unit Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).
10.5		Form of Non-Qualified Stock Option Award Agreement (2016 Awards) (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).
10.6		Form of Non-Qualified Stock Option Award Agreement (CEO) (2016 Awards) (incorporated by reference to Exhibit 10.6 to the Current Report on Form 8-K of Dynegy Inc. filed on March 14, 2016 File No. 001-33443).
10.7		Equity Commitment Letter, dated as of February 24, 2016, by and among Dynegy Inc., Atlas Power, LLC and Atlas Power Finance, LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.8		Equity Commitment Letter, dated as of February 24, 2016, by and among Energy Capital Partners III, LP, Energy Capital Partners III-A, LP, Energy Capital Partners III-B, LP, Energy Capital Partners III-C, LP, Energy Capital Partners III-D, LP, Atlas Power, LLC and Atlas Power Finance, LLC (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.9		Limited Guarantee, dated February 24, 2016, by Dynegy Inc., for the benefit of GDF SUEZ Energy North America, Inc. (incorporated by reference to Exhibit 10.3 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.10		Stock Purchase Agreement, dated February 24, 2016, by and between Dynegy Inc. and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.4 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
10.11		Interim Sponsors Agreement, dated February 24, 2016, by and between Atlas Power, LLC, Dynegy Inc., Energy Capital Partners III, LP, Energy Capital Partners III-A, LP, Energy Capital Partners III-B, LP, Energy Capital Partners III-C, LP and Energy Capital Partners III-D, LP (incorporated by reference to Exhibit 10.5 to the Current Report on Form 8-K of Dynegy Inc. filed on March 1, 2016 File No. 001-33443).
**31.1		Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
**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.


*	Schedules and exhibits to the Stock Purchase Agreement have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Dynegy will furnish the omitted schedules and exhibits to the Securities and Exchange Commission upon request by the Commission.

† 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.

8366

DYNEGY INC.

SIGNATURE

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



			DYNEGY INC.

Date:	~~November 5, 2015~~May 4, 2016	By:	/s/ CLINT C. FREELAND
			Clint C. Freeland Executive Vice President and Chief Financial Officer

8467



	Fair Value as of September 30, 2015
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	257		$	102		$	359
Natural gas derivatives	—			43			5			48
Emissions derivatives	—			5			—			5
Coal derivatives	—			7			4			11
Total assets from commodity risk management activities	$	—		$	312		$	111		$	423
Liabilities:										.
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(193	)	$	(151	)	$	(344	)
Natural gas derivatives	—			(174		)	(19		)	(193		)
Heat rate derivatives	—			—			(2		)	(2		)
Diesel fuel derivatives	—			(5		)	—			(5		)
Coal derivatives	—			(40		)	(1		)	(41		)
Total liabilities from commodity risk management activities	—			(412		)	(173		)	(585		)
Liabilities from interest rate contracts	—			(48		)	—			(48		)
Liabilities from outstanding common stock warrants	(18		)	—			—			(18		)
Total liabilities	$	(18	)	$	(460	)	$	(173	)	$	(651	)



	Nine Months Ended September 30, 2015
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Coal Derivatives			Total
Balance at December 31, 2014	$	(4	)	$	—		$	—		$	—		$	(4	)
Acquisitions	(54		)	(14		)	(9		)	5			(72		)
Total gains included in earnings	7			—			—			—			7
Settlements (1)	2			—			7			(2		)	7
Balance at September 30, 2015	$	(49	)	$	(14	)	$	(2	)	$	3		$	(62	)
Unrealized gains relating to instruments held as of September 30, 2015	$	7		$	—		$	—		$	—		$	7



	Nine Months Ended September 30, 2014
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Coal Derivatives		Total
Balance at December 31, 2013	$	11		$	—		$	(1	)	$	—	$	10
Total losses included in earnings	(19		)	(1		)	—			—		(20		)
Settlements (1)	(5		)	—			1			—		(4		)
Balance at September 30, 2014	$	(13	)	$	(1	)	$	—		$	—	$	(14	)
Unrealized losses relating to instruments held as of September 30, 2014	$	(19	)	$	(1	)	$	—		$	—	$	(20	)



	EquiPower Acquisition				Duke Midwest Acquisition
(amounts in millions/months)	Gross Carrying Amount			Weighted-Average Amortization Period	Gross Carrying Amount			Weighted-Average Amortization Period
Intangible Assets:
Electricity contracts	$	71		32	$	80		38
Coal contracts	—			—	—			9
Gas transport contracts	40			24	4			19
Total intangible assets	$	111		29	$	84		37

Intangible Liabilities:
Electricity contracts	$	—		—	$	(10	)	23
Coal contracts	(10		)	21	(83		)	27
Coal transport contracts	(23		)	22	—			—
Gas contracts	—			1	—			—
Gas transport contracts	(40		)	128	—			—
Total intangible liabilities	$	(73	)	81	$	(93	)	27
Total intangible assets and liabilities, net	$	38			$	(9	)



(amounts in millions)	September 30, 2015
Balance, December 31, 2014	$	224
Accretion expense	15
Liabilities settled in the current period	(4		)
Acquisitions	105
Balance, September 30, 2015	$	340



	Winter 2013-2014	Summer 2014	Winter 2014-2015	Summer 2015	Winter 2015-2016	Summer 2016	Winter 2016-2017	Summer 2017
Price per kW-month	$2.58	$5.15	$2.90	$3.50	$2.30	$3.48	$2.25	$2.87



Period	(a) Total Number of Shares Purchased	(b) Average Price Paid per Share		(c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (1)	(d) Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
July 1 - July 31	—	$	—	—	$	—
August 1 - August 31	4,996,299	$	25.37	4,996,299	$	123,000,000
September 1 - September 30	—	$	—	—	$	—
Total	4,996,299	$	25.37	4,996,299	$	123,000,000

Price per MW-day