Item 1—FINANCIAL STATEMENTS

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2016		December 31, 2015
ASSETS
Current Assets
Cash and cash equivalents	$	1,776	$	505
Restricted cash	62		39
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	386		402
Inventory	445		597
Assets from risk management activities	130		100
Intangible assets	38		102
Prepayments and other current assets	150		187
Total Current Assets	2,987		1,932
Property, plant and equipment, net	7,121		8,347
Investment in unconsolidated affiliate	—		190
Restricted cash	2,000		—
Assets from risk management activities	16		18
Goodwill	799		797
Intangible assets	23		62
Other long-term assets	107		113
Total Assets	$	13,053	$	11,459

See the notes to consolidated financial statements.

F-4

DYNEGY INC.

CONSOLIDATED BALANCE SHEETS

(in millions, except share data)

	December 31, 2016			December 31, 2015
LIABILITIES AND EQUITY
Current Liabilities
Accounts payable	$	332		$	292
Accrued interest	81			74
Intangible liabilities	21			85
Accrued liabilities and other current liabilities	133			125
Liabilities from risk management activities	97			103
Asset retirement obligations	51			50
Debt, current portion, net	201			80
Total Current Liabilities	916			809
Liabilities subject to compromise (Note 22)	832			—
Debt, long-term portion, net	8,778			7,129
Liabilities from risk management activities	43			105
Asset retirement obligations	236			230
Deferred income taxes	5			29
Intangible liabilities	34			55
Other long-term liabilities	170			183
Total Liabilities	11,014			8,540
Commitments and Contingencies (Note 17)

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
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,626,740 shares issued and 117,300,618 shares outstanding at December 31, 2016; 128,228,477 shares issued and 116,902,355 outstanding at December 31, 2015	1			1
Additional paid-in capital	3,547			3,187
Accumulated other comprehensive income, net of tax	21			19
Accumulated deficit	(1,927		)	(686		)
Total Dynegy Stockholders’ Equity	2,042			2,921
Noncontrolling interest	(3		)	(2		)
Total Equity	2,039			2,919
Total Liabilities and Equity	$	13,053		$	11,459

See the notes to consolidated financial statements.

F-5

DYNEGY INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Year Ended December 31,
	2016			2015			2014
Revenues	$	4,318		$	3,870		$	2,497
Cost of sales, excluding depreciation expense	(2,281		)	(2,028		)	(1,661		)
Gross margin	2,037			1,842			836
Operating and maintenance expense	(940		)	(839		)	(477		)
Depreciation expense	(689		)	(587		)	(247		)
Impairments	(858		)	(99		)	—
Gain (loss) on sale of assets, net	(1		)	(1		)	18
General and administrative expense	(161		)	(128		)	(114		)
Acquisition and integration costs	(11		)	(124		)	(35		)
Other	(17		)	—			—
Operating income (loss)	(640		)	64			(19		)
Bankruptcy reorganization items (Note 22)	(96		)	—			3
Earnings from unconsolidated investments	7			1			10
Interest expense	(625		)	(546		)	(223		)
Other income and expense, net	65			54			(39		)
Loss before income taxes	(1,289		)	(427		)	(268		)
Income tax benefit (Note 15)	45			474			1
Net income (loss)	(1,244		)	47			(267		)
Less: Net income (loss) attributable to noncontrolling interest	(4		)	(3		)	6
Net income (loss) attributable to Dynegy Inc.	(1,240		)	50			(273		)
Less: Dividends on preferred stock	22			22			5
Net income (loss) attributable to Dynegy Inc. common stockholders	$	(1,262	)	$	28		$	(278	)

Earnings (Loss) Per Share (Note 16):
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders	$	(9.78	)	$	0.22		$	(2.65	)

Basic shares outstanding	129			125			105
Diluted shares outstanding	129			126			105

See the notes to consolidated financial statements.

F-6

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	(1,244	)	$	47		$	(267	)
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	689			587			247
Non-cash interest expense	56			38			21
Amortization of intangibles	21			(11		)	45
Impairments	858			99			—
Risk management activities	(148		)	(130		)	26
(Gain) loss on sale of assets, net	1			1			(18		)
Earnings from unconsolidated investments	(7		)	(1		)	—
Deferred income taxes	(45		)	(477		)	(1		)
Change in value of common stock warrants	(6		)	(54		)	40
Bankruptcy reorganization items	96			—			—
Other	14			51			35
Changes in working capital:
Accounts receivable, net	42			(64		)	161
Inventory	154			(119		)	(20		)
Prepayments and other current assets	94			94			8
Accounts payable and accrued liabilities	84			25			(66		)
Distributions from unconsolidated investments	1			3			—
Changes in non-current assets	(43		)	—			3
Changes in non-current liabilities	28			5			7
Net cash provided by operating activities	645			94			221
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(293		)	(301		)	(125		)
Acquisitions, net of cash acquired	—			(6,078		)	—
Distributions from unconsolidated affiliates	14			8			—
Proceeds from asset sales, net	176			—			18
Other investing	10			3			—
Net cash used in investing activities	(93		)	(6,368		)	(107		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	3,014			66			5,055
Repayments of borrowings	(589		)	(31		)	(14		)
Proceeds from issuance of equity, net of issuance costs	359			(6		)	1,106
Preferred stock dividends paid	(22		)	(23		)	—
Interest rate swap settlement payments	(17		)	(17		)	(18		)
Repurchase of common stock	—			(250		)	—
Other financing	(3		)	(4		)	(3		)
Net cash provided by (used in) financing activities	2,742			(265		)	6,126
Net increase (decrease) in cash, cash equivalents, and restricted cash	3,294			(6,539		)	6,240
Cash, cash equivalents, and restricted cash, beginning of period	544			7,083			843
Cash, cash equivalents, and restricted cash, end of period	$	3,838		$	544		$	7,083

See the notes to consolidated financial statements.

F-8

DYNEGY INC.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in millions)

	Preferred Stock		Common Stock		Additional Paid-In Capital			AOCI			Accumulated Deficit			Total Controlling Interests			Noncontrolling Interest			Total
December 31, 2013	$	—	$	1	$	2,614		$	58		$	(463	)	$	2,210		$	(3	)	$	2,207
Net income (loss)	—		—		—			—			(273		)	(273		)	6			(267		)
Other comprehensive loss, net of tax	—		—		—			(38		)	—			(38		)	(3		)	(41		)
Share-based compensation expense, net of tax	—		—		17			—			—			17			—			17
Options exercised	—		—		1			—			—			1			—			1
Issuance of new equity interests (Note 18)	400		—		706			—			—			1,106			—			1,106
December 31, 2014	400		1		3,338			20			(736		)	3,023			—			3,023
Net income (loss)	—		—		—			—			50			50			(3		)	47
Equity issuance for acquisition, net (Note 18)	—		—		99			—			—			99			—			99
Other comprehensive income (loss), net of tax	—		—		—			(1		)	—			(1		)	1			—
Share-based compensation expense, net of tax	—		—		22			—			—			22			—			22
Options exercised	—		—		1			—			—			1			—			1
Dividends paid	—		—		(23		)	—			—			(23		)	—			(23		)
Repurchases of common stock (Note 18)	—		—		(250		)	—			—			(250		)	—			(250		)
December 31, 2015	400		1		3,187			19			(686		)	2,921			(2		)	2,919
Net loss	—		—		—			—			(1,240		)	(1,240		)	(4		)	(1,244		)
TEUs (Note 18)	—		—		359			—			—			359			—			359
Other comprehensive income, net of tax	—		—		—			2			—			2			2			4
Share-based compensation expense, net of tax	—		—		22			—			—			22			—			22
Dividends paid	—		—		(22		)	—			—			(22		)	—			(22		)
Other	—		—		1			—			(1		)	—			1			1
December 31, 2016	$	400	$	1	$	3,547		$	21		$	(1,927	)	$	2,042		$	(3	)	$	2,039

See the notes to consolidated financial statements.

F-9

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1—Organization and Operations

We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. 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. In the fourth quarter of 2016, we changed our organizational structure to manage our assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. As of December 31, 2016, we modified our reportable segments from a fuel-based segment structure to the following market areas: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) MISO, (iv) IPH, and (v) CAISO. Accordingly, the Company has recast data from prior periods to reflect this change in reportable segments. Additionally, beginning in 2017, as a result of the Delta Transaction, we also have an ERCOT segment. 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 23—Segment Information for further discussion.

On December 9, 2016, Illinois Power Generating Company (“Genco”) filed a petition (the “Bankruptcy Petition”) under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On January 25, 2017, the Bankruptcy Court confirmed the prepackaged plan of reorganization (the “Genco Plan”) and Genco emerged from bankruptcy on February 2, 2017 (the “Emergence Date”). As a result, we eliminated $825 million of Genco Senior Notes. On the Emergence Date, we exchanged $757 million of these Genco Senior Notes for $113 million of cash, $182 million of new Dynegy seven year unsecured notes, and 8.7 million Dynegy common stock warrants. Holders of Genco Senior Notes who did not receive a distribution under the Genco Plan on the Emergence Date have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution. As of December 31, 2016, Genco remained a consolidated variable interest entity (“VIE”) within our consolidated financial statements. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

Through the Emergence Date, IPH and its direct and indirect subsidiaries were organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and our other legal entities. Certain of the entities in the IPH segment, including Genco, had an independent director whose consent was required for certain corporate actions, including material transactions with affiliates. Further, there were restrictions on pledging their assets for the benefit of certain other persons. These provisions restricted our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.

Note 2—Summary of Significant Accounting Policies

Principles of Consolidation. The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries and VIEs for which we are the primary beneficiary. Intercompany accounts and transactions have been eliminated. Certain prior period amounts in our consolidated financial statements have been reclassified to conform to current year presentation. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America (“U.S.”).

Unconsolidated Investments. We use the equity method of accounting for investments in affiliates over which we exercise significant influence. We use the cost method of accounting where we do not exercise significant influence.

Our share of net income (loss) from these affiliates is reflected in the consolidated statements of operations as Earnings from unconsolidated investments. All investments in unconsolidated affiliates are periodically assessed for other-than-temporary declines in value, with write-downs recognized in Earnings from unconsolidated investments in the consolidated statements of operations.

Undivided Interest Accounting. We account for our undivided interests in certain of our coal-fired power generation facilities whereby our proportionate share of each facility’s assets, liabilities, revenues, and expenses are included in the appropriate classifications in the accompanying consolidated financial statements.

Noncontrolling Interest. Noncontrolling interest is comprised of the 20 percent of Electric Energy, Inc. (“EEI”) which we do not own. This noncontrolling interest is classified as a component of equity separate from our equity in the consolidated balance sheets.

Use of Estimates. The preparation of consolidated financial statements in conformity with Generally Accepted Accounting Principles (“GAAP”) requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. We review significant estimates and judgments affecting our consolidated financial statements on a recurring basis and record the effect of any necessary adjustments. Uncertainties with respect

F-10

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

to such estimates and judgments are inherent in the preparation of financial statements. Estimates and judgments are used in, among other things: (i) developing fair value assumptions, including estimates of future cash flows and discount rates related to impairment analyses and business combinations, (ii) valuation of derivative instruments, (iii) analyzing tangible and intangible assets for possible impairment, (iv) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (v) assessing future tax exposure and the realization of deferred tax assets, (vi) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (vii) estimating various factors used to value our pension assets and liabilities. Actual results could differ materially from our estimates. In the opinion of management, all adjustments considered necessary for a fair presentation have been included in our consolidated financial statements.

Cash and Cash Equivalents. Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid short-term investments with original maturities of three months or less.

Restricted Cash. Restricted cash represents cash that is not readily available for general purpose cash needs. Restricted cash is classified as a current or long-term asset based on the timing and nature of when or how the cash is expected to be used or when the restrictions are expected to lapse. As of December 31, 2016 and 2015, the Company had the following restricted cash balances:

	Year Ended December 31,
(amounts in millions)	2016		2015
Restricted cash, current:
Cash deposits associated with certain letters of credit (1)	$	41	$	39
Pre-funded original issue discount on Tranche C Term Loan (2)	20		—
Interest earned on funds in escrow	1		—
	$	62	$	39
Restricted cash, long-term:
Restricted cash related to the issuance of the Tranche C Term Loan (2)	$	2,000	$	—

(1) Upon the Emergence Date, approximately $35 million of these deposits were returned to Dynegy.

(2) Upon the close of the Delta Transaction, as defined herein, the proceeds from the issuance of the Tranche C Term Loan were released from escrow. Please read Note 14—Debt for further information.

Accounts Receivable and Allowance for Doubtful Accounts. We record accounts receivable at net realizable value (“NRV”) when the product or service is delivered to the customer. We establish provisions for losses on accounts receivable if it becomes probable that we will not collect all or part of outstanding balances. We review collectability and establish or adjust our allowance as necessary using the specific identification method.

Inventory. Our commodity and materials and supplies inventories are carried at the lower of weighted average cost or NRV.

Property, Plant and Equipment. Property, plant and equipment (“PP&E”), which consists principally of power generating facilities, including capitalized interest, is generally recorded at historical cost. Expenditures for major installations, replacements, and improvements or betterments are capitalized and depreciated over the expected life cycle. Expenditures for maintenance, repairs, and minor renewals to maintain the operating condition of our assets are expensed. Depreciation is recognized using the straight-line method over the estimated economic service lives of the assets, ranging from one to 40 years.

The estimated economic service lives of our asset groups are as follows:

Asset Group		Range of Years
Power generation		1 to 36
Buildings and improvements		4 to 40
Office and other equipment		3 to 20

Gains and losses on sales of assets are reflected in Gain (loss) on sale of assets, net in the consolidated statements of operations. We evaluate our PP&E for impairment when events or changes in circumstances indicate that the carrying value of an asset may not be recoverable. If an impairment is indicated, the carrying value is first compared to the undiscounted cash flows for the asset’s remaining useful life to determine if the carrying value is recoverable. In the event the carrying value is not recoverable, an impairment is recognized for the amount of carrying value in excess of the asset’s fair value. As a result of impairment analyses

F-11

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

performed in 2016, we determined that our Stuart, Newton, and Baldwin facilities were impaired resulting in an aggregate impairment charge of $849 million for the year ended December 31, 2016. Please read Note 9—Property, Plant and Equipment for further information.

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 is 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. Once we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent) to be less than its carrying amount, the two-step impairment test will be performed.

In the absence 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.

As of October 1, 2016, we performed our annual goodwill assessment and no goodwill impairment was required.

Intangible Assets and Liabilities. We initially record and measure intangible assets and liabilities (“Intangibles”) based on the fair value of those rights transferred in the transaction in which the asset was acquired. Our recognized Intangibles consist of contractual rights and obligations with finite lives, and their initial values are based on quoted market prices, if available, or measurement techniques based on the best information available such as a present value of future cash flows. We amortize our definite-lived Intangibles over the useful life of the respective contracts.

Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundments and landfill closure, dismantlement of power generation facilities, future removal of asbestos-containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring, and land obligations. Accretion expense is included in Operating and maintenance expense in our consolidated statements of operations. A summary of the changes related to our AROs is as follows:

	Year Ended December 31,
(amounts in millions)	2016			2015
Balance at beginning of year	$	280		$	224
Accretion expense	20			21
Liabilities incurred	—			4
Liabilities settled	(1		)	(4		)
Revision of previous estimate (1)	(12		)	(57		)
Acquisitions	—			92
Balance at end of year	$	287		$	280

(1) Based on management’s review and assessment of CCR compliance timing and site-specific analysis.

Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, and proceedings in the normal course of our operations. We record a loss contingency for these matters when it is probable that a liability has been incurred and the amount of the loss can be reasonably estimated. We review our loss contingencies on an ongoing basis to ensure that we have appropriate reserves recorded in our consolidated balance sheets. These reserves are based on estimates and judgments made by management with respect to the likely outcome of these matters, including any applicable insurance coverage, and are adjusted as circumstances warrant. Liabilities for environmental contingencies are recorded when an environmental assessment indicates that remedial efforts are probable and the costs can be reasonably estimated. Measurement of liabilities is based, in part, on relevant past experience, currently enacted laws and regulations, existing technology, site-specific costs, and cost-sharing arrangements. Recognition of any joint and several liability is based upon our best estimate of our final pro-rata share of such liability.

F-12

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

We enter into various guarantees and indemnifications during the ordinary course of business. When a guarantee or indemnification is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances; however, management also considers the probability of such circumstances occurring when estimating the fair value.

Preferred Stock. Our preferred shares are mandatorily convertible, are not redeemable and are classified as stockholders’ equity. We present the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares are cumulative and are presented as a reduction of net income (or increase of net loss) to derive net income (loss) attributable to common shareholders on the consolidated statements of operations. Dividends are recognized in stockholders’ equity in the period in which they are declared, and are presented as a financing activity on the consolidated statements of cash flows when paid.

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 in our consolidated balance sheets as a reduction of Additional paid-in capital.

Revenue Recognition. We earn revenue from our facilities in three primary ways: (i) the sale of energy through both physical and financial transactions to optimize the financial performance of our generating facilities; (ii) the sale of capacity; and (iii) the sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load, and provide emergency reserves for major changes to the balance of generation and load. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative. Please read “Derivative Instruments—Generation” for further discussion of the accounting for these types of transactions.

Derivative Instruments—Generation. We enter into commodity contracts that meet the definition of a derivative. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to buy or sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. All derivative commodity contracts that do not qualify for the “normal purchase, normal sale” exception are recorded at fair value in Risk management assets and liabilities in the consolidated balance sheets. We elect not to apply hedge accounting to our derivative commodity contracts; therefore, changes in fair value are recorded currently in Revenues in our consolidated statements of operations. As a result, these mark-to-market gains and losses are not reflected in the consolidated statements of operations in the same period as the underlying activity for which the derivative instruments serve as economic hedges. Derivative instruments and related cash collateral or margin that are executed with the same counterparty under a master netting agreement are reflected on a net basis in the consolidated balance sheets.

Cash inflows and cash outflows associated with the settlement of risk management activities are recognized in net cash provided by (used in) operating activities on the consolidated statements of cash flows.

Derivative Instruments—Financing Activities. We are exposed to changes in interest rates through our variable rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements. We elect not to apply hedge accounting to our interest rate derivative contracts; therefore, changes in fair value are recorded currently in earnings through interest expense. Cash settlements related to our current interest rate contracts are classified as either inflows or outflows from financing activities on the consolidated statements of cash flows due to an other-than-insignificant financing element at inception of these contracts. Please read Note 14—Debt for more information.

Fair Value Measurements. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority.

The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

· Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing

F-13

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities, and U.S. government treasury securities.

· Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standard models or other valuation methodologies in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options, and swaps.

· Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

The determination of fair value incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and, when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Income Taxes. We file a consolidated U.S. federal income tax return. IPH and its subsidiaries operate under a tax sharing agreement with Dynegy. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant timing differences as of each reporting date.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation. These differences can result in deferred tax assets and liabilities which are included within our consolidated balance sheets and are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business.

The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In making this determination, we consider all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities, and the implementation of tax planning strategies.

Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.

Please read Note 15—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

Earnings (Loss) Per Share. Basic earnings (loss) per share represents the amount of earnings for the period available to each share of common stock outstanding during the period. Diluted earnings (loss) per share includes the effect of issuing shares of common stock, assuming (i) stock options and warrants are exercised, (ii) restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the prepaid stock purchase contracts (“SPCs”) are converted into common stock under the if-converted method.

Business Combinations Accounting. The Company accounts for its business combinations in accordance with ASC 805, Business Combinations (“ASC 805”), which requires an acquirer to recognize and measure in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at fair value at the acquisition date. It also requires an acquirer to measure any goodwill acquired and determine what information to disclose to enable users of an entity’s

F-14

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Year Ended December 31,
(amounts in millions)	2016			2015			2014
CASH FLOWS FROM OPERATING ACTIVITIES:
As previously reported	$	676		$	94		$	163
Prepayments for future planned outage work performed under long-term service agreements	(33		)	26			(7		)
Changes in restricted cash	2			(26		)	65
As currently reported	$	645		$	94		$	221

CASH FLOWS FROM INVESTING ACTIVITIES:
As previously reported	$	(2,147	)	$	(1,194	)	$	(5,262	)
Prepayments for future planned outage work performed under long-term service agreements	33			(26		)	7
Changes in restricted cash	2,021			(5,148		)	5,148
As currently reported	$	(93	)	$	(6,368	)	$	(107	)

Accounting Standards Not Yet Adopted

Goodwill. In January 2017, the FASB issued ASU 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate Step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We do not anticipate the adoption of this ASU to have a material impact on our consolidated financial statements.

Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to 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 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, 2018, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our consolidated financial statements.

Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU, and subsequently issued amendments to the standard, develop a common revenue standard 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 guidance in this ASU and its amendments 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 have established an implementation team to assess the impact the new accounting standard will have on our financial statements upon adoption. Our implementation team is currently assessing the impact of the standard by reviewing revenue earned from contracts to determine if changes in our policies are necessary. While our evaluation of the new accounting standard is still ongoing, we have not yet identified any significant changes to our existing policies.

Note 3—Acquisitions

EquiPower Acquisition. 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 purchased 100 percent of

F-16

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

As of June 30, 2016, we completed our valuation of the assets acquired and liabilities assumed in connection with the Acquisitions. The following table summarizes the consideration paid and the fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and the Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015:

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

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

Accounts payable	27		96			123
Accrued liabilities and other current liabilities	21		10			31
Debt, current portion	39		—			39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)	57		107			164
Asset retirement obligations	43		49			92
Intangible liabilities (including current portion of $24 million and $58 million, respectively)	73		93			166
Deferred income taxes, net	509		—			509
Other long-term liabilities	—		40			40
Total liabilities assumed	769		395			1,164
Identifiable net assets acquired	2,862		2,791			5,653
Goodwill	799		—			799
Net assets acquired	$	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 initially recorded a net deferred tax liability of $537 million within our provisional valuation of the EquiPower Acquisition as of the acquisition date. 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 deferred tax liabilities during the second quarter of 2015. During the second half of 2015, we reduced the initially-recognized deferred tax liability by $31 million due to newly available information regarding the fair values of assets and liabilities acquired in the EquiPower Acquisition. This reduction to the deferred tax liability resulted primarily in a corresponding reduction to goodwill, as discussed below, and a $27 million reversal of the previously released valuation allowance discussed above. For the year ended December 31, 2015, we recorded a net deferred tax liability of $506 million and released approximately $453 million of our valuation allowance related to the EquiPower Acquisition.

F-18

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Goodwill resulting from the EquiPower Acquisition reflects the excess of our purchase price over the fair value of the net assets acquired. We recorded initial goodwill of $837 million as of the acquisition date, and subsequently reduced the amount during the second half of 2015 by $40 million due to the newly available information discussed above. As of December 31, 2016 and 2015, we recognized goodwill of $799 million and $797 million, which was allocated to our segments as follows:

	Year Ended December 31,
(amounts in millions)	2016		2015
PJM	$	272	$	271
NY/NE	527		526
Total	$	799	$	797

None of the goodwill recognized is deductible for income tax purposes, and as such, no deferred taxes related to goodwill have been recorded. No goodwill was recognized as a result of the Duke Midwest Acquisition.

The following table summarizes acquisition costs incurred related to the Acquisitions, which are included in Acquisition and integration costs in our consolidated statements of operations, and revenues and operating income (loss) attributable to the Acquisitions, which are included in our consolidated statements of operations:

	Year Ended December 31,
(amounts in millions)	2016		2015		2014
Acquisition costs (1)	$	—	$	86	$	19
Revenues	$	2,280	$	1,703	N/A
Operating income	$	235	$	230	N/A

(1) The year ended December 31, 2015, included $48 million of 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, as our permanent financing for the Acquisitions was executed.

Pro Forma Results. The unaudited pro forma financial results for the years ended December 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 acquisitions been completed on January 1, 2014, nor are they indicative of future results of operations.

	Year Ended December 31,
(amounts in millions)	2015			2014
Revenues	$	4,860		$	5,574
Net income (loss)	$	308		$	(613	)
Net income (loss) attributable to noncontrolling interest	$	(3	)	$	6
Net income (loss) attributable to Dynegy Inc.	$	311		$	(619	)

Note 4—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.

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 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,”

F-19

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

in accordance with ASC 815, Derivatives and Hedging. As a result, the gains and losses with respect to these arrangements are not reflected in the consolidated statements of operations until the delivery occurs.

Quantitative Disclosures Related to Financial Instruments and Derivatives

As of December 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)
(dollars and quantities in millions)	Purchases (Sales)			Asset (Liability)
Commodity contracts:
Electricity derivatives (2)	(69	)	MWh	$	(115	)
Electricity basis derivatives (3)	(21	)	MWh	$	(4	)
Natural gas derivatives (2)	423		MMBtu	$	123
Natural gas basis derivatives	61		MMBtu	$	(12	)
Emissions derivatives	8		Metric Ton	$	(10	)
Interest rate swaps	769		U.S. Dollar	$	(30	)
Common stock warrants (4)	16		Warrant	$	(1	)

(1) Includes both asset and liability risk management positions, but excludes margin and collateral netting of $54 million.

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

(3) Comprised of FTRs and swaps.

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

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

		December 31, 2016
					Gross amounts offset in the balance sheet
Contract Type	Balance Sheet Location	Gross Fair Value			Contract Netting			Collateral or Margin Received or Paid		Net Fair Value
(amounts in millions)
Derivative assets:
Commodity contracts	Assets from risk management activities	$	311		$	(165	)	$	—	$	146
Total derivative assets		$	311		$	(165	)	$	—	$	146

Derivative liabilities:
Commodity contracts	Liabilities from risk management activities	$	(329	)	$	165		$	54	$	(110	)
Interest rate contracts	Liabilities from risk management activities	(30		)	—			—		(30		)
Common stock warrants	Accrued liabilities and other current liabilities	(1		)	—			—		(1		)
Total derivative liabilities		$	(360	)	$	165		$	54	$	(141	)
Total derivatives		$	(49	)	$	—		$	54	$	5

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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

Derivative liabilities:
Commodity contracts	Liabilities from risk management activities	$	(557	)	$	285		$	106	$	(166	)
Interest rate contracts	Liabilities from risk management activities	(42		)	—			—		(42		)
Common stock warrants	Other long-term liabilities	(7		)	—			—		(7		)
Total derivative liabilities		$	(606	)	$	285		$	106	$	(215	)
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 worsen, 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. As of December 31, 2016, the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features which are in a liability position and not fully collateralized is $15 million for which we have posted $9 million in collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program.

The following table summarizes our cash collateral posted as of December 31, 2016 and 2015, within Prepayments and other current assets in our consolidated balance sheets, and the amount applied against short-term risk management activities:

Location on Balance Sheet	December 31, 2016		December 31, 2015
(amounts in millions)
Gross collateral posted with counterparties	$	116	$	162
Less: Collateral netted against risk management liabilities	54		106
Net collateral within Prepayments and other current assets	$	62	$	56

Impact of Derivatives on the Consolidated Statements of Operations

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 consolidated statements of operations.

Our consolidated statements of operations for the years ended December 31, 2016, 2015 and 2014 include the impact of derivative financial instruments as presented below.

	Location of Gain (Loss) Recognized in	Year Ended December 31,
Derivatives Not Designated as Hedges	Income on Derivatives	2016			2015			2014
(amounts in millions)
Commodity contracts	Revenues	$	270		$	194		$	(183	)
Interest rate contracts	Interest expense	$	(5	)	$	(15	)	$	(15	)
Common stock warrants	Other income and (expense), net	$	6		$	54		$	(40	)

F-21

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 5—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 for further discussion.

The finance organization monitors commodity risk through the Commodity Risk Control Group (“CRCG”). The Executive Management Team (“EMT”) monitors interest rate risk. The EMT has delegated the responsibility for managing interest rate risk to the Chief Financial Officer (“CFO”). The CRCG is independent of our commercial operations and has direct access to the Audit Committee. The Finance and Risk Management Committee, comprised of members of management and chaired by the CFO, meets periodically and is responsible for reviewing our overall day-to-day energy commodity risk exposure, as measured against the limits established in our Commodity Risk Policy. Each quarter, as part of its internal control processes, representatives from the CRCG review the methodology and assumptions behind the pricing of the forward curves. As part of this review, liquidity periods are established based on third party market information, the basis relationship between direct and derived curves is evaluated, and changes are made to the forward power model assumptions.

The CRCG reviews changes in value on a daily basis through the use of various reports. The pricing for power, natural gas, and fuel oil curves is automatically entered into our commercial system nightly based on data received from our market data provider. The CRCG reviews the data provided by the market data provider by utilizing third party broker quotes for comparison purposes. In addition, our traders are required to review various reports to ensure accuracy on a daily basis.

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 December 31, 2016 and 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.

	Fair Value as of December 31, 2016
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	118		$	20		$	138
Natural gas derivatives	—			169			4			173
Total assets from commodity risk management activities	$	—		$	287		$	24		$	311
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(245	)	$	(12	)	$	(257	)
Natural gas derivatives	—			(52		)	(10		)	(62		)
Emissions derivatives	—			(10		)	—			(10		)
Total liabilities from commodity risk management activities	—			(307		)	(22		)	(329		)
Liabilities from interest rate contracts	—			(30		)	—			(30		)
Liabilities from outstanding common stock warrants	(1		)	—			—			(1		)
Total liabilities	$	(1	)	$	(337	)	$	(22	)	$	(360	)

F-22

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Fair Value as of December 31, 2015
(amounts in millions)	Level 1			Level 2			Level 3			Total
Assets:
Assets from commodity risk management activities:
Electricity derivatives	$	—		$	308		$	40		$	348
Natural gas derivatives	—			40			2			42
Coal derivatives	—			10			3			13
Total assets from commodity risk management activities	$	—		$	358		$	45		$	403
Liabilities:
Liabilities from commodity risk management activities:
Electricity derivatives	$	—		$	(267	)	$	(58	)	$	(325	)
Natural gas derivatives	—			(158		)	(34		)	(192		)
Diesel derivatives	—			(4		)	—			(4		)
Coal derivatives	—			(35		)	(1		)	(36		)
Total liabilities from commodity risk management activities	—			(464		)	(93		)	(557		)
Liabilities from interest rate contracts	—			(42		)	—			(42		)
Liabilities from outstanding common stock warrants	(7		)	—			—			(7		)
Total liabilities	$	(7	)	$	(506	)	$	(93	)	$	(606	)

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 December 31, 2016 are as follows:

Transaction Type	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)	(8	)	Million MWh	$	10		Basis spread + liquid location	Basis spread	$4.30 - $6.30
FTRs	(19	)	Million MWh	$	(2	)	Historical congestion	Forward price	$0 - $6.00
Natural gas derivatives (1)	73		Million MMBtu	$	(6	)	Illiquid location fixed price	Forward price	$2.00 - $2.50

(1) Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.

F-23

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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:

	Year Ended December 31, 2016
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Coal Derivatives			Total
Balance at December 31, 2015	$	(18	)	$	(32	)	$	2		$	(48	)
Total gains (losses) included in earnings	59			49			(4		)	104
Settlements (1)	(33		)	(23		)	2			(54		)
Balance at December 31, 2016	$	8		$	(6	)	$	—		$	2
Unrealized gains (losses) relating to instruments held as of December 31, 2016	$	59		$	49		$	(4	)	$	104

	Year Ended December 31, 2015
(amounts in millions)	Electricity Derivatives			Natural Gas Derivatives			Heat Rate Derivatives			Coal Derivatives			Total
Balance at December 31, 2014	$	(4	)	$	—		$	—		$	—		$	(4	)
Total gains included in earnings	39			3			—			—			42
Settlements (1)	1			28			9			(2		)	36
Acquisitions	(54		)	(63		)	(9		)	4			(122		)
Balance at December 31, 2015	$	(18	)	$	(32	)	$	—		$	2		$	(48	)
Unrealized gains relating to instruments held as of December 31, 2015	$	39		$	3		$	—		$	—		$	42

	Year Ended December 31, 2014
(amounts in millions)	Electricity Derivatives			Heat Rate Derivatives			Total
Balance at December 31, 2013	$	11		$	(1	)	$	10
Total gains (losses) included in earnings	(9		)	1			(8		)
Settlements (1)	(6		)	—			(6		)
Balance at December 31, 2014	$	(4	)	$	—		$	(4	)
Unrealized gains (losses) relating to instruments held as of December 31, 2014	$	(9	)	$	1		$	(8	)

(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 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 years ended December 31, 2016 and 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 such assets and liabilities and their placement within the fair value hierarchy.

During the year ended December 31, 2016, as a result of impairment testing, we measured our Baldwin, Newton and Stuart facilities at fair value. During the year ended December 31, 2015, as a result of impairment testing, we measured our Wood River Power Station and Brayton Point generation facilities at fair value. See Note 9—Property, Plant and Equipment for further discussion. During the year ended December 31, 2015, we fair valued the EquiPower and Duke Midwest acquisitions. See Note 3—Acquisitions for further discussion. Each of these valuations is classified as Level 3 within the fair value hierarchy.

F-24

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments which are not recognized at fair value in our 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 December 31, 2016 and 2015, respectively.

		December 31, 2016						December 31, 2015
(amounts in millions)	Fair Value Hierarchy	Carrying Amount			Fair Value			Carrying Amount			Fair Value
Dynegy Inc.:
6.75% Senior Notes, due 2019 (1)	Level 2	$	(2,083	)	$	(2,137	)	$	(2,077	)	$	(1,985	)
Tranche B-2 Term Loan, due 2020 (1)	Level 2	$	(219	)	$	(225	)	$	(766	)	$	(754	)
Tranche C Term Loan, due 2023 (1)	Level 2	$	(1,994	)	$	(2,025	)	$	—		$	—
7.375% Senior Notes, due 2022 (1)	Level 2	$	(1,731	)	$	(1,665	)	$	(1,729	)	$	(1,531	)
5.875% Senior Notes, due 2023 (1)	Level 2	$	(492	)	$	(431	)	$	(491	)	$	(404	)
7.625% Senior Notes, due 2024 (1)	Level 2	$	(1,237	)	$	(1,156	)	$	(1,235	)	$	(1,078	)
8.00% Senior Notes, due 2025 (1)	Level 2	$	(738	)	$	(703	)	$	—		$	—
7.00% Amortizing Notes, due 2019 (1)	Level 2	$	(78	)	$	(90	)	$	—		$	—
Forward capacity agreement (1)	Level 3	$	(205	)	$	(205	)	$	—		$	—
Inventory financing agreements	Level 3	$	(129	)	$	(127	)	$	(136	)	$	(137	)
Equipment financing agreements (1)	Level 3	$	(73	)	$	(73	)	$	(61	)	$	(61	)
Genco:
7.00% Senior Notes Series H, due 2018 (1)	Level 2	$	—		$	—		$	(276	)	$	(204	)
6.30% Senior Notes Series I, due 2020 (1)	Level 2	$	—		$	—		$	(213	)	$	(148	)
7.95% Senior Notes Series F, due 2032 (1)	Level 2	$	—		$	—		$	(225	)	$	(162	)
Liabilities subject to compromise (2)	Level 3	$	(825	)	$	(366	)	$	—		$	—

(1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 14—Debt for further discussion.

(2) Carrying amounts represent the Genco senior notes that have been classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a level 3 valuation due to a lack of observable inputs that make up the consideration. Please read Note 22—Genco Chapter 11 Bankruptcy for further details.

Concentration of Credit Risk. We sell our energy products and services to customers in the electric and natural gas distribution industries, financial institutions, residential customers and to entities engaged in commercial and industrial businesses. These industry concentrations have the potential to impact our overall exposure to credit risk, either positively or negatively, because the customer base may be similarly affected by changes in economic, industry, weather or other conditions.

At December 31, 2016 and 2015, our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $79 million and $45 million, respectively.

Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our credit risk system provides current credit exposure to counterparties on a daily basis. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. We enter into master netting agreements in an attempt to both mitigate credit exposure and reduce collateral requirements. In general, the agreements include our risk management subsidiaries and allow the aggregation of credit exposure, margin and set-off. We attempt to further reduce credit risk with certain counterparties by obtaining third party guarantees or collateral as well as the right of termination in the event of default. As a result, we decrease a potential credit loss arising from a counterparty default.

We include cash collateral deposited with brokers and cash paid to non-broker counterparties which has not been offset against risk management liabilities in Prepayments and other current assets in our consolidated balance sheets. As of December 31, 2016 and 2015, we had $62 million and $56 million recorded to Prepayments and other current assets, respectively. We include cash collateral received from non-broker counterparties in Accrued liabilities and other current liabilities in our consolidated balance sheets. As of December 31, 2016 and 2015, we were not holding any collateral received from counterparties.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 6—Accumulated Other Comprehensive Income

Changes in accumulated other comprehensive income (“AOCI”), net of tax, by component are as follows:

	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Beginning of period	$	19		$	20		$	58
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments (net of tax of $3, zero, and zero, respectively)	2			3			(33		)
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero) (1)	5			—			—
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively) (2)	(5		)	(4		)	(5		)
Net current period other comprehensive income (loss), net of tax	2			(1		)	(38		)
End of period	$	21		$	19		$	20

(1) Amount is related to the EEI other post-employment benefit plan settlement cost and was recorded in Operating and maintenance expense in our consolidated statements of operations. Please read Note 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(2) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read Note 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Note 7—Cash Flow Information

The supplemental disclosures of cash flow and non-cash investing and financing information are as follows:

	Year Ended December 31,
(amounts in millions)	2016			2015		2014
Interest paid (net of amount capitalized of $10, $12, and $9, respectively)	$	548		$	491	$	120
Taxes paid (net of refunds)	$	(1	)	$	2	$	—
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	$	(13	)	$	10	$	23
Change in capital expenditures pursuant to equipment financing agreements	$	11		$	61	$	—
Non-cash consideration transferred for acquisitions	$	—		$	105	$	—

Note 8—Inventory

A summary of our inventories is as follows:

(amounts in millions)	December 31, 2016		December 31, 2015
Materials and supplies	$	182	$	178
Coal (1)	238		350
Fuel oil (1)	17		17
Emissions allowances (2)	8		51
Other	—		1
Total	$	445	$	597

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

(1) At December 31, 2016, approximately $44 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 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 14—Debt—Brayton Point Inventory Financing for further discussion.

(2) At December 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. Please read Note 14—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)	December 31, 2016			December 31, 2015
Power generation	$	7,537		$	8,178
Buildings and improvements	944			956
Office and other equipment	98			101
Property, plant and equipment	8,579			9,235
Accumulated depreciation	(1,458		)	(888		)
Property, plant and equipment, net	$	7,121		$	8,347

The following table summarizes total interest costs incurred and interest capitalized related to costs of construction projects in process:

	Year Ended December 31,
(amounts in millions)	2016		2015		2014
Total interest costs incurred	$	556	$	487	$	187
Capitalized interest	$	10	$	12	$	9

Impairments

During the years ended December 31, 2016 and 2015, we recognized the following impairments in our consolidated statements of operations:

Facility	Fair Value		2016		2015
Stuart (1)	$	—	$	56	$	—
Newton FGD (2)	$	—	148		—
Baldwin (3)	$	97	645		—
Wood River (4)	$	—	—		74
Brayton Point (5)	$	86	—		25
Total			$	849	$	99

(1) On-going required maintenance and environmental capital expenditures combined with consistently poor reliability and a determination that the facility would experience recurring negative cash flows.

(2) The flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility was terminated.

(3) Units failed to recover their basic operating costs in the most recent MISO auction.

(4) Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs.

(5) Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility will retire in June 2017.

Valuation Methodology

We performed step two of the impairment analysis for each facility, excluding Newton, using a DCF model with a discount rate between 9 and 13 percent, assuming normal operations for the estimated remaining useful lives of the facilities. For the model, gross margin was based on forward commodity market prices obtained from third party quotations for the first two years, and for the

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

subsequent eight years, we used commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors. For each year of the remaining useful life of each facility beyond the first ten years, we assumed a 2.5 percent growth rate per year, based upon management’s view of future conditions. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for five years and assumed a 2.5 percent growth rate. For the Newton facility, since the FGD project was abandoned, we wrote down the FGD assets to their salvage value, which was less than $1 million.

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, 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 consolidated statements of operations.

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

	December 31, 2016
(dollars in millions)	Ownership Interest		Property, Plant and Equipment		Accumulated Depreciation			Construction Work in Progress		Total
Miami Fort	64.0	%	$	207	$	(39	)	$	4	$	172
Stuart (1)	39.0	%	$	—	$	—		$	4	$	4
Conesville (1)	40.0	%	$	61	$	(3	)	$	6	$	64
Zimmer	46.5	%	$	115	$	(25	)	$	6	$	96
Killen (1)	33.0	%	$	19	$	(2	)	$	3	$	20

	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) Facilities not operated by Dynegy.

Note 11—Unconsolidated Investments

Equity Method Investments

Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in the Elwood Energy facility to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). Elwood Energy owns a 1,580 MW natural gas-fired facility located in Elwood, Illinois. During the third quarter of 2016, we recorded a charge of $9 million to Impairments in our consolidated statements of operations to write down our investment in Elwood to the sales price. Additionally, approximately $35 million of previously posted collateral was returned to Dynegy at closing.

For the years ended December 31, 2016 and 2015, we recorded $7 million and $1 million in equity earnings related to our investment in Elwood, respectively, which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2016, we received distributions of $15 million, of which $14 million was considered a return of investment. For the year ended December 31, 2015, we received distributions of $11 million, of which $8 million was considered a return of investment. As of December 31, 2016 and 2015, we have approximately zero and $3 million in accounts receivable due from Elwood, which is included in Accounts receivable in our consolidated balance 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

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

facility in Nevada. We received $17 million in cash proceeds upon the close of the transaction, which is reflected in Gain on sale of assets, net in our consolidated statements of operations for the year ended December 31, 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 from unconsolidated investments in our consolidated statements of operations for the year ended December 31, 2014.

Note 12—Intangible Assets and Liabilities

The following table summarizes the components of our intangible assets and liabilities as of December 31, 2016 and 2015:

	December 31, 2016									December 31, 2015
(amounts in millions)	Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount			Gross Carrying Amount			Accumulated Amortization			Net Carrying Amount
Intangible Assets:
Electricity contracts	$	260		$	(206	)	$	54		$	260		$	(126	)	$	134
Gas transport contracts	13			(6		)	7			46			(16		)	30
Total intangible assets	$	273		$	(212	)	$	61		$	306		$	(142	)	$	164

Intangible Liabilities:
Electricity contracts	$	(28	)	$	26		$	(2	)	$	(30	)	$	19		$	(11	)
Coal contracts	(49		)	42			(7		)	(134		)	82			(52		)
Coal transport contracts	(86		)	73			(13		)	(104		)	64			(40		)
Gas transport contracts	(41		)	8			(33		)	(64		)	27			(37		)
Total intangible liabilities	$	(204	)	$	149		$	(55	)	$	(332	)	$	192		$	(140	)
Intangible assets and liabilities, net	$	69		$	(63	)	$	6		$	(26	)	$	50		$	24

The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Electricity contracts, net (1)	$	70		$	75		$	96
Coal contracts, net (2)	(41		)	(60		)	(14		)
Coal transport contracts, net (2)	(27		)	(32		)	(29		)
Gas transport contracts, net (2)	19			6			(8		)
Total	$	21		$	(11	)	$	45

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

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

Amortization expense (revenue), net for the next five years as of December 31, 2016 is as follows: 2017—$17 million, 2018—$4 million, 2019—$1 million, 2020—($1) million and 2021—($3) million.

Note 13—Tangible Equity Units

In 2016, we issued 4.6 million, 7 percent tangible equity units (“TEUs”) at $100 per unit and received proceeds of $443 million, net of issuance costs of $17 million.

Each TEU is comprised of: (i) a prepaid SPC issued by Dynegy, and (ii) an amortizing note (“Amortizing Note”), with an initial principal amount of $18.95 that pays an equal quarterly cash installment of $1.75 per Amortizing Note on January 1, April 1, July 1, and October 1 of each year, with the exception of the first installment payment of $1.94 due on October 1, 2016. In the aggregate, the annual quarterly cash installments are equivalent to a 7 percent cash payment per year. Each installment cash payment constitutes a payment of interest and a partial repayment of principal. Each TEU may be separated by a holder into its constituent SPC and Amortizing Note after the initial issuance date of the TEUs, and the separate components may be combined to

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

create a TEU after the initial issuance date, in accordance with the terms of the SPC. The TEUs are listed on the New York Stock Exchange under the symbol “DYNC”.

We allocated the proceeds from the issuance of the TEUs, including other fees and expenses, to equity and debt based on the relative fair value of the respective components of each TEU as follows:

(in millions, except price per TEU)	SPC			Amortizing Note			Total
Price per TEU	$	81		$	19		$	100

Gross proceeds	$	373		$	87		$	460
Less: Issuance costs	(14		)	(3		)	(17		)
Net proceeds	$	359		$	84		$	443

The fair value of the SPCs was recorded as additional paid in capital, net of issuance costs. The fair value of the Amortizing Notes was recorded as debt, with deferred financing costs recorded as a reduction of the carrying amount of the debt in our consolidated balance sheet. Deferred financing costs related to the Amortizing Notes will be amortized through the maturity date using the effective interest rate method.

Unless settled early at the holder’s or Dynegy’s election or redeemed by Dynegy in connection with an acquisition termination redemption, on July 1, 2019, Dynegy will deliver to the SPC holders a number of shares of common stock based on the 20 day volume-weighted average price (“VWAP”) of our common stock as follows:

VWAP of Dynegy Common Stock		Common Shares Issued
Equal to or greater than $19.92		5.0201 shares (minimum settlement rate)
Less than $19.92, but greater than $16.13		$100 divided by VWAP
Less than or equal to $16.13		6.1996 shares (maximum settlement rate)

In addition, on any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the TEUs to, but excluding, the third business day immediately preceding the mandatory settlement date, any holder of an SPC may settle any or all of its SPCs early, and Dynegy will deliver a number of shares of Common Stock equal to the minimum settlement rate. Additionally, the SPCs may be redeemed in the event of a fundamental change or under an acquisition termination event, both as defined in the SPC.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 14—Debt

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

(amounts in millions)	December 31, 2016			December 31, 2015
Secured Obligations:
Dynegy Inc.:
Tranche B-2 Term Loan, due 2020	$	224		$	780
Tranche C Term Loan, due 2023 (1)	2,000			—
Revolving Facility	—			—
Forward Capacity Agreement	219			—
Inventory Financing Agreements	129			136
Subtotal secured obligations	2,572			916
Unsecured Obligations:
Dynegy Inc.:
7.00% Amortizing Notes, due 2019 (TEUs)	80			—
6.75% Senior Notes, due 2019	2,100			2,100
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
8.00% Senior Notes, due 2025 (2)	750			—
Equipment Financing Agreements	97			75
Subtotal unsecured obligations	6,527			5,675
Total Dynegy Inc.	9,099			6,591
Genco Unsecured Obligations (3):
7.00% Senior Notes Series H, due 2018	—			300
6.30% Senior Notes Series I, due 2020	—			250
7.95% Senior Notes Series F, due 2032	—			275
Total Genco	—			825
Total debt obligations	9,099			7,416
Unamortized debt discounts and issuance costs (4)	(120		)	(207		)
	8,979			7,209
Less: Current maturities, including unamortized debt discounts and issuance costs, net	201			80
Total Long-term debt	$	8,778		$	7,129

(1) At December 31, 2016, the escrowed term loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our consolidated balance sheet. Upon the close of the Delta Transaction, this debt obligation became Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion.

(2) The $750 million, 8 percent unsecured senior notes (the “2025 Senior Notes”) do not provide registration rights but otherwise have terms and provisions similar to our approximately $5.6 billion in senior notes (“Dynegy Senior Notes”).

(3) On December 9, 2016, Genco filed a prepackaged plan of reorganization Chapter 11 Case (the “Chapter 11 Case”). As a result, we reclassified the Genco unsecured obligations as Liabilities subject to compromise in our December 31, 2016 consolidated balance sheet. Additionally, we wrote off approximately $94 million of remaining unamortized debt discount. See Note 22—Genco Chapter 11 Bankruptcy for further discussion.

(4) Includes $111 million of unamortized debt discounts as of December 31, 2015 relating to the Genco unsecured obligations.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2016 are as follows:

	(in millions)
2017	$	210
2018	212
2019	2,200
2020	262
2021	31
Thereafter	6,184
Total	$	9,099

Credit Agreement and Finance IV Credit Agreement

As of December 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 facility (the “Tranche B-2 Term Loan”) and (ii) $1.425 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). Additionally, we had a $2.0 billion, seven-year senior term loan, under the Finance IV Credit Agreement, as defined below.

During 2016, we made $6 million of required payments as well as a voluntary repayment in the amount of $550 million on the Tranche B-2 Term Loan.

At December 31, 2016, there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $302 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. Beginning December 31, 2016 and thereafter, the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00. Based on the calculation outlined in the Credit Agreement, we are in compliance as of December 31, 2016.

Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt. Further, the balance of the Tranche C Term Loan is excluded from Net Debt until the closing of the Delta Transaction, whereupon it becomes Dynegy Inc.’s secured obligation.

Finance IV Credit Agreement. On June 27, 2016 (the “Term Loan Closing Date”), Finance IV entered into a term loan credit agreement which provided for a $2.0 billion, seven-year Tranche C Term Loan, which would mature on June 27, 2023. The Tranche C Term Loan bore interest at either (i) 4 percent per annum plus LIBOR, subject to a floor of 1 percent with respect to any LIBOR Loan or (ii) 3 percent per annum plus the Base Rate with respect to any Base Rate Loan.

Proceeds of the term loan were placed into escrow pending the consummation of the Delta Transaction. Dynegy additionally contributed $70 million into escrow so that the aggregate funds in the Escrow Account would be sufficient to repay the term loan plus any interest that may accrue for a period of six months from the Term Loan Closing Date. The Finance IV Credit Agreement contained limited events of default and affirmative covenants and one negative covenant, which restricted the activities of Finance IV to those primarily relating to the Delta Transaction and financing. The obligations of Finance IV under the Finance IV Credit Agreement were secured by the related amounts placed in escrow from time to time.

As of December 31, 2016, we had $2.0 billion classified as long-term Restricted cash and $21 million classified as short-term Restricted cash in our consolidated balance sheet related to the Escrow Agreement.

Following the release of funds from escrow upon the satisfaction of the Delta Transaction Escrow Conditions, as defined in the Finance IV Credit Agreement (the “Escrow Release Date”), Finance IV was merged with and into Dynegy, with Dynegy as the surviving entity, and Dynegy used the amounts released from escrow to fund a portion of the Delta Transaction.

Interest Rate Swaps

During 2013, 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 $769 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 swaps are reflected as a financing activity in our consolidated statements of cash flows.

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DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Amortizing Notes

On June 21, 2016, in connection with the issuance of the TEUs, Dynegy issued the Amortizing Notes with a principal amount of approximately $87 million. The Amortizing Notes mature on July 1, 2019. Each installment payment of $1.75 (or, in the case of the installment payment due on October 1, 2016, $1.94) per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7 percent. Interest will be calculated on the basis of a 360 day year consisting of twelve 30 day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the Indenture. Please read Note 13—Tangible Equity Units for further discussion.

The Indenture limits, among other things, the ability of Dynegy to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if Dynegy elects to settle the SPCs early or to redeem the SPCs in connection with a termination of the Delta Stock Purchase Agreement, then the holders of the Amortizing Notes will have the right to require Dynegy to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The Indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness, the failure to satisfy covenants, and specified events of bankruptcy and insolvency.

Letter of Credit Facilities

Dynegy has an LC Reimbursement Agreement with Macquarie Bank Limited (“Macquarie Bank”), for an LC in an amount not to exceed $55 million. The expiry date of the facility was extended in August 2016 to September 19, 2017. At December 31, 2016, there was $55 million outstanding under this LC.

Illinois Power Marketing Company (“IPM”) has LC and reimbursement agreements with issuing banks in which the issuing banks agree to issue standby LCs in stated amounts not to exceed $50 million, in aggregate, to support performance obligations and other general corporate activities of IPM and IPRG. As of December 31, 2016, there were $25 million in LCs outstanding under these facilities. The IPM LC facilities are collateralized by cash, and as of December 31, 2016, IPM had $19 million deposited with the issuing banks. Upon the Emergence Date, these LCs were released and cash was returned to Dynegy.

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 in excess of the $15 million line of credit are cash collateralized.

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 costs, and other expenses. The debt obligation increases for 85 percent of the total cost of the coal and for 90 percent of the total cost of the fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil costs, respectively. We repay the debt obligation and line of credit from revenues received, at the then market price, for the amount of the materials consumed on a weekly basis.

As of December 31, 2016, there was $51 million outstanding under this agreement. Both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3-month LIBOR plus 5.6 percent. An availability fee is calculated on a per annum rate of 0.25 percent. Additionally, we had collateral postings of approximately zero. The Inventory Financing Agreement terminates, and the remaining obligation, if any, becomes due and payable, on May 31, 2017.

Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. We are obligated to repurchase a portion of the

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inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent. As of December 31, 2016, there was $78 million, in aggregate, outstanding under these agreements.

In 2013, we entered into two repurchase transactions in which we sold $6 million in California Carbon Allowances (“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.

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. 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 consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $73 million. The $24 million discount is currently amortized as interest expense over the life of the payments.

Genco Senior Notes

Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) were an obligation of Genco, a subsidiary of IPH. The Genco Senior Notes were non-recourse to Dynegy. Please read Note 1—Organization and Operations for further discussion.

On December 9, 2016, Genco filed a Bankruptcy Petition commencing a prepackaged Chapter 11 Case. Genco continued to operate its business as debtor-in possession until the Emergence Date. We reclassified the $825 million face value of the Genco unsecured obligations to Liabilities subject to compromise in our December 31, 2016 consolidated balance sheet and charged $94 million of unamortized debt discount to Bankruptcy reorganization items in our consolidated statement of operations. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

Note 15—Income Taxes

Income Tax Benefit. We are subject to U.S. federal and state income taxes on our operations.

Our losses from continuing operations before income taxes were $1.289 billion, $427 million and $268 million for the years ended December 31, 2016, 2015 and 2014, respectively, which was solely from domestic sources.

Our components of income tax benefit related to income (loss) from continuing operations were as follows:

	Year Ended December 31,
(amounts in millions)	2016		2015			2014
Current tax benefit (expense)	$	15	$	(3	)	$	—
Deferred tax benefit	30		477			1
Income tax benefit	$	45	$	474		$	1

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Our income tax benefit related to losses from continuing operations before income taxes for each of the years ended December 31, 2016, 2015 and 2014 were equivalent to effective rates of 3 percent, 111 percent, and zero percent, respectively. Differences between taxes computed at the U.S. federal statutory rate and our reported income tax benefit were as follows:

	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Expected tax benefit at U.S. statutory rate (35%)	$	451		$	149		$	94
State taxes	16			68			—
Permanent differences (1)	(4		)	16			(15		)
Valuation allowance (2)(3)	(404		)	271			(331		)
NOL reduction from acceleration of AMT Credits	(17		)	—			—
Uncertain tax position	—			—			244
Unconsolidated subsidiary adjustment	—			—			5
Adjustment to AMT credits	—			(26		)	—
Other	3			(4		)	4
Income tax benefit	$	45		$	474		$	1

(1) Permanent items for years ended December 31, 2016, 2015 and 2014 included a $2 million benefit, an $18 million benefit, and a $14 million expense, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. Income tax benefit for the year ended December 31, 2016 includes $5 million of Income tax expense for non-deductible legal fees related to the Genco Plan. Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

(2) The EquiPower Acquisition on April 1, 2015 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $453 million reduction to our valuation allowance in 2015 and $3 million in 2016.

(3) On April 14, 2014, we received final notice from the Internal Revenue Service (“IRS”) that their audit of our 2012 tax year has been completed. In accordance with accounting guidance in ASC 740, Income Taxes (“ASC 740”), we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in the second quarter of 2014 as a discrete item with a corresponding adjustment to the valuation allowance.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows:

	Year Ended December 31,
(amounts in millions)	2016			2015
Non-current deferred tax assets:
NOL carryforwards	$	1,629		$	1,533
AMT and state tax credit carryforwards	241			275
Reserves (legal, environmental and other)	7			17
Pension and other post-employment benefits	18			16
Asset retirement obligations	85			89
Deferred financing costs and intangible/other contracts	48			64
Derivative contracts	57			69
Other	46			27
Subtotal	2,131			2,090
Less: valuation allowance	(1,704		)	(1,276		)
Total non-current deferred tax assets	$	427		$	814
Non-current deferred tax liabilities:
Depreciation and other property differences	$	(371	)	$	(738	)
Investment in unconsolidated partnership	—			(27		)
Derivative contracts	(44		)	(4		)
Other	(17		)	(74		)
Total non-current deferred tax liabilities	$	(432	)	$	(843	)
Net non-current deferred tax liabilities	$	(5	)	$	(29	)

NOL Carryforwards. As of December 31, 2016, we had approximately $4.2 billion of federal tax net operating loss carryforwards (“NOLs”) and $3.4 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2036. Similarly, the state NOLs will expire at various dates (based on the company’s review of the application of apportionment factors and other state tax limitations). Under federal income tax law, our NOLs can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Internal Revenue Code (“IRC”) Section 382. If an ownership change were to occur as a result of future transactions in our stock, our ability to utilize the NOLs may be significantly limited.

Alternative Minimum Tax Credit Carryforwards. While our Alternative Minimum Tax (“AMT”) credits do not expire, the change in control that occurred on May 9, 2012 materially impacted our ability to utilize the AMT credits. The Company filed an amended 2009 tax return on April 8, 2015, as permitted by the IRS, which allows the Company to utilize more AMT NOLs. This relief resulted in a reduction of AMT credits of $26 million. For the year ended December 31, 2016, the Company elected to accelerate the minimum tax credit in lieu of claiming the bonus depreciation allowance, resulting in a current Income tax benefit of $16 million.

Change in Valuation Allowance. Realization of our deferred tax assets is dependent upon, among other things, our ability to generate taxable income of the appropriate character in the future. At December 31, 2016, we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 2016, our temporary differences were in a net deferred tax asset position. We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available, to realize the tax benefits of our net deferred tax asset associated with temporary differences. Accordingly, we have recorded a full valuation allowance against the net asset temporary differences related to federal income tax and the net asset temporary differences related to most state income tax as appropriate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

The changes in the valuation allowance were as follows:

	Year Ended December 31,
	2016		2015			2014
Beginning of period	$	1,276	$	1,535		$	1,149
Changes in valuation allowance—continuing operations:
Charged to costs and expenses	428		(259		)	370
Charged to other accounts	—		—			16
End of period	$	1,704	$	1,276		$	1,535

Unrecognized Tax Benefits. We are complete with federal income tax audits by the IRS through 2013 as a result of our participation in the IRS’ Compliance Assurance Process. However, any NOLs we claim in future years to reduce taxable income could be subject to additional IRS examination regardless of when the NOLs occurred. We are generally not subject to examinations for state and local taxes for tax years 2010 or earlier with few exceptions.

On April 14, 2014, we received final notice from the IRS that their audit of our 2012 tax year was completed. In accordance with accounting guidance in ASC 740, we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in 2014 as a discrete item with a corresponding adjustment to the valuation allowance.

A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows:

	Year Ended December 31,
amounts in millions	2016		2015			2014
Unrecognized tax benefits, beginning of period	$	3	$	4		$	274
Decrease due to settlements and payments	—		(1		)	(270		)
Unrecognized tax benefits, end of period	$	3	$	3		$	4

As of December 31, 2016, approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Note 16—Earnings (Loss) Per Share

Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if converted method. Please read Note 18—Capital Stock and Note 13—Tangible Equity Units for further discussion.

The following table reflects the significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(in millions, except per share amounts)	2016	2015		2014
Shares outstanding at the beginning of the period	117	124		100
Weighted-average shares during the period of:
Shares issuances	—	4		5
Shares repurchases	—	(3	)	—
Prepaid stock purchase contract (TEUs) (1)	12	—		—
Basic weighted-average shares	129	125		105
Dilution from potentially dilutive shares (2)	—	1		—
Diluted weighted-average shares	129	126		105

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(1) The minimum settlement amount, or 23,092,460 shares, are considered to be outstanding since June 21, 2016, and are included in the computation of basic earnings (loss) per share. Please read Note 13—Tangible Equity Units for further discussion.

(2) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2016 and 2014.

For the years ended December 31, 2016, 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:

	Year Ended December 31,
(in millions of shares)	2016	2015	2014
Stock options	2.8	0.5	1.4
Restricted stock units	1.3	—	1.0
Performance stock units	1.2	—	0.3
Warrants	15.6	15.6	15.6
Series A 5.375% mandatory convertible preferred stock	12.9	12.9	4.0
TEUs	5.4	—	—
Total	39.2	29.0	22.3

Note 17—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, 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.

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.

Gas Index Pricing Litigation. We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. 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. On May 23, 2014, the Texas Supreme Court vacated the arbitration 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 IGC’s $17 million payment remains pending. On December 16, 2014, the Dallas District Court entered a judgment requiring the return of the $17 million to IGC and an additional $2.5 million payment to IGC for interest. PPE paid the $17 million in principal and the $2.5 million in interest to IGC. On July 14, 2016, the Dallas Court of Appeals affirmed the judgment. PPE’s deadline to appeal the judgment to the Texas Supreme Court has expired. We recognized a gain of $20 million which is included in Other income and expense, net in our consolidated statements of operations for the year ended December 31, 2016.

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Advatech Dispute. On September 2, 2016, Genco terminated its Second Amended and Restated Newton FGD System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC. Advatech issued Genco its final invoice on September 30, 2016 totaling $81 million. Genco contested the invoice on October 3, 2016. Genco does not believe Advatech calculated the termination payment correctly, but does owe Advatech a final payment of $0.5 million as well as demobilization costs which Advatech claims are $0.7 million. On October 27, 2016, Advatech initiated the dispute resolution process under the Contract. Settlement discussions required under the dispute resolution process have been unsuccessful. The next step is arbitration, which has not been initiated yet. Dynegy views the risk of a material loss as remote.

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., 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. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. 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.

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. 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. This decision may provide an additional defense to the allegations in the Newton facility NOV. In September 2016, we retired Newton Unit 2.

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. As of June 1, 2016, our Wood River facility has been retired.

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 jointly 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. In

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August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has not yet scheduled the remedy phase of the case. 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 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 National Pollutant Discharge Elimination System (“NPDES”) Permit Appeal. In January 2013, the Ohio EPA reissued the NPDES permit for the jointly 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.

MISO Segment Groundwater. In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities.

At Baldwin, with approval of the IEPA, we performed a comprehensive evaluation of the Baldwin CCR surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the IEPA 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 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of the closure plan.

We initiated an investigation at Baldwin in 2011 at the request of the IEPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the IEPA 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 IEPA in 2012. Our hydrogeological 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 IEPA 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 IEPA 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.

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 IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In 2015, we submitted an assessment monitoring report to the IEPA that identifies the Newton facility’s inactive unlined landfill as the likely source of groundwater quality exceedances at the facility’s active CCR landfill. In August 2016, IEPA approved the report. We are monitoring groundwater in accordance with IEPA’s approval.

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 CCR surface 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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 AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014 and await IEPA action.

In response to the Baldwin report, we notified the EPA in 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 evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs.

Other Commitments

In conducting our operations, we routinely enter 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. The following describes the significant commitments outstanding at December 31, 2016.

Coal Purchase Commitments. At December 31, 2016, we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $827 million. To the extent purchased or committed 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. At December 31, 2016, we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $823 million.

Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. Recently we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. As of December 31, 2016, our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $410 million in the event all contracts are terminated by us.

In addition, during this year we have committed to securing capital spares for our gas-fueled generation fleet to help minimize production disturbances. As of December 31, 2016, we have obligations to purchase spare parts of $24 million with payments made through 2026, of which $11 million reflects spare parts received. Upon the receipt of the parts and transfer of title to Dynegy, we recognize the asset and the associated payment obligation at the NPV of those payments, which we record to PP&E and Debt in our consolidated balance sheets.

Gas Purchase Commitments. At December 31, 2016, we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $420 million.

Gas Transportation. At December 31, 2016, we had 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 $173 million.

Operating Leases.

Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases are $5 million per year for the years 2017-2021.

During the years ended December 31, 2016, 2015 and 2014, we recognized rental expense of approximately $5 million, $5 million and $5 million, respectively.

Charter Agreement. The aggregate minimum base commitments of our charter party agreement are approximately $5 million for the year ended December 31, 2017. We are party to one charter agreement related to a very large gas carrier (“VLGC”) previously utilized in our former global liquids business. The primary term of the charter was through September 2014 but has been extended through September 2017 at the option of the counterparty. The VLGC has been sub-chartered to a wholly owned subsidiary of Transammonia Inc. on terms that are identical to the terms of the original charter agreement. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement and has not exercised the remaining optional extension.

Other Obligations. We have other obligations of $31 million for contracts in place to purchase limestone, $22 million for interconnection services and $32 million for other miscellaneous items which are individually insignificant.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

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.

Note 18—Capital Stock

Preferred Stock

We have authorized preferred stock consisting of 20 million shares, $0.01 par value. Our preferred stock may be issued from time to time in one or more series, the shares of each series to have such designations and powers, preferences, rights, qualifications, limitations and restrictions thereof as specified by our Board of Directors. As of December 31, 2016, there were 4 million shares of our Series A Mandatory Convertible Preferred Stock (as described below) issued and outstanding.

Series A Mandatory Convertible Preferred Stock. On October 14, 2014, we issued 4 million shares, $0.01 par value, pursuant to a registered public offering, of our 5.375% Series A Mandatory Convertible Preferred Stock (“Mandatory Convertible Preferred Stock”) at $100 per share, for gross proceeds of approximately $400 million, before underwriting discounts and commissions of $13 million (“Mandatory Convertible Preferred Stock Offering”). These issuance costs are included in Additional paid-in capital in our consolidated balance sheets.

The Mandatory Convertible Preferred Stock has a liquidation preference of $100 per share, or an aggregate preference of $400 million. Dividends accrue at 5.375 percent per annum on the liquidation preference and will be payable on a cumulative basis when and if declared by our Board of Directors. 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 on February 1, May 1, August 1 and November 1 of each year, commencing on February 1, 2015, and to, and including, November 1, 2017. In the first quarter of 2015, we paid a dividend of $1.64 per share. In each quarter from the second quarter of 2015 to the fourth quarter of 2016, we paid a dividend of $1.34 per share.

As long as we are not in default on our credit agreements, we are not restricted from paying dividends on the Mandatory Convertible Preferred Stock. During the years ended December 31, 2016 and 2015, we paid an aggregate of $22 million and $23 million in dividends, respectively. We paid no dividends during 2014.

Each share of Mandatory Convertible Preferred Stock will, unless previously converted, automatically convert on November 1, 2017, into between 2.5806 and 3.2258 shares of our common stock, subject to anti-dilution and other adjustments. The Mandatory Convertible Preferred Stock is not redeemable by us. The holders of the Mandatory Convertible Preferred Stock generally have no voting rights except in the case of dividend arrearages. Holders are not entitled to participate in any dividends which may be declared and paid on our common stock.

At any time prior to November 1, 2017, other than during a Fundamental Change Conversion Period (as defined in the Certificate of Designations for the Mandatory Convertible Preferred Stock (the “Certificate of Designations”)), holders of the Mandatory Convertible Preferred Stock have the right to elect to convert their shares in whole or in part at the Minimum Conversion Rate of 2.5806 shares of our common stock per share of Mandatory Convertible Preferred Stock. This Minimum Conversion Rate is subject to certain anti-dilution adjustments. The Certificate of Designations provides that during a Fundamental Change Conversion Period, the shares may be converted by the holder at the Fundamental Change Conversion Rate, as defined therein.

TEUs

On June 21, 2016, pursuant to a registered public offering, we issued 4.6 million, 7 percent TEUs at $100 per unit. Each TEU was comprised of a prepaid stock purchase contract and an amortizing note which were accounted for as separate instruments. Please read Note 13—Tangible Equity Units for further discussion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Common Stock

Upon our emergence from bankruptcy on October 1, 2012 (the “Plan Effective Date”), we authorized 420 million shares of common stock, $0.01 par value per share, of which 11,326,122 shares are currently held in treasury. The following table reflects balances and activity in our outstanding shares of common stock, for the years ended December 31, 2016, 2015 and 2014:

	Shares outstanding balance as of December 31,
(in millions)	2016	2015		2014
Beginning of period	117	124		100
Common stock offering, including shares sold through underwriter’s option	—	—		24
Shares issued as consideration for the ECP Acquisition	—	3		—
Shares repurchases (in treasury)	—	(11	)	—
Share issued under long-term compensation plans	—	1		—
End of period	117	117		124

Warrants. As of the Plan Effective Date, we issued to Legacy Dynegy stockholders warrants to purchase up to 15.6 million shares of common stock for an exercise price of $40 per share (the “2012 Warrants”). The 2012 Warrants have a five-year term expiring on October 2, 2017. If the exercise price of the 2012 Warrants is greater than the market price of Dynegy’s common stock upon the determination date of a Subject Transaction, such distributions are equivalent to $0.01 per warrant, or approximately $150 thousand for all 2012 Warrants outstanding. As a result of a potential fixed distribution, these warrants are classified as a liability in our consolidated financial statements and are adjusted to their estimated fair value at the end of each reporting period with the change in fair value recognized in Other income (expense) in our consolidated statement of operations. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

Stock Award Plans

We have one stock award plan, the Dynegy Amended and Restated 2012 Long Term Incentive Plan (the “A&R 2012 LTIP”), which provides for the issuance of authorized shares of our common stock. Restricted Stock Units (“RSUs”), Performance Stock Units (“PSUs”) and option grants have been issued under the A&R 2012 LTIP. The A&R 2012 LTIP is a broad-based plan and provides for the issuance of approximately 3.2 million authorized shares through May 2026.

All options granted under the A&R 2012 LTIP cease vesting for employees who are terminated with cause. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate or continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon exercise of stock options from previously unissued shares. Any options granted under the A&R 2012 LTIP will expire no later than 10 years from the date of the grant.

All RSUs granted under the A&R 2012 LTIP contain a service condition and cease vesting for employees or directors who are terminated with cause. For severance-eligible employee terminations, as defined under the severance pay plan, director terminations without cause, employee or director disability, retirement or death, immediate vesting of some or all of the RSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon vesting of RSUs from previously unissued shares, with the exception of 1.5 million shares of RSU’s granted in 2016 to be settled in cash. As these awards must be settled in cash, we account for them as liabilities, with changes in the fair value of the liability recognized as expense in our consolidated statements of operations.

All PSUs granted under the A&R 2012 LTIP contain a performance condition and cease vesting for employees who do not remain continuously employed during the performance period under the grant agreements. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate vesting of some or all of the PSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Upon a corporate change, employees receive an immediate vesting of PSUs regardless of whether the employee is terminated.

We use the fair value based method of accounting for stock-based employee compensation. Compensation expense related to options, RSUs and PSUs granted totaled $31 million, $28 million and $19 million for the years ended December 31, 2016, 2015 and 2014, respectively. We recognize compensation expense ratably over the vesting period of the respective awards. Tax benefits for compensation expense related to options, RSUs and PSUs granted totaled $11 million, $10 million and $7 million for the years ended December 31, 2016, 2015 and 2014, respectively. As of December 31, 2016, $25 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 1.46 years. The total fair value of options, RSUs and PSUs vested was $27 million, $18 million and $14 million for the years ended December 31,

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2016, 2015 and 2014, respectively. We did not capitalize or use cash to settle any share-based compensation in the years ended December 31, 2016, 2015 and 2014.

No options were exercised for the year ended December 31, 2016. Cash received from option exercises for the years ended December 31, 2015 and 2014 was $0.5 million and $1 million, respectively, and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the years ended December 31, 2015 and 2014.

The following summarizes our stock option activity:

	Year Ended December 31, 2016
	Options (in thousands)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (in years)	Aggregate Intrinsic Value (amounts in millions)
Outstanding at beginning of period	1,832		$	22.81
Granted	979		$	11.05
Forfeited	(6	)	$	29.56
Outstanding at end of period	2,805		$	18.69	8.11	$	—
Vested and unvested expected to vest	2,805		$	18.69	8.11	$	—
Exercisable at end of period	1,370		$	21.69	6.9	$	—

During the years ended December 31, 2016, 2015 and 2014, we did not grant any options at an exercise price less than the market price on the date of grant. The weighted average exercise price of options granted during the years ended December 31, 2015 and 2014 was $27.43 and $23.03, respectively. The intrinsic value of options exercised during the years ended December 31, 2015 and 2014 was less than $1 million.

For stock options, we determine the fair value of each stock option at the grant date using a Black-Scholes model, with the following weighted-average assumptions used for grants:

	Year Ended December 31,
	2016			2015			2014
Dividend Yield	$	—		$	—		$	—
Expected volatility (1)	41.19		%	27.70		%	23.96		%
Risk-free interest rate (2)	1.42		%	1.64		%	1.61		%
Expected option life (3)	5.5 years			5.5 years			5.5 years
Weighted average grant-date fair value	$	4.37		$	7.93		$	5.91

(1) For the years ended December 31, 2016, 2015 and 2014, the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012.

(2) The risk-free interest rate was calculated based upon observed interest rates appropriate for the term of our employee stock options.

(3) Currently, we calculate the expected option life using the simplified methodology suggested by authoritative guidance issued by the SEC.

The following summarizes our RSU activity:

	Year Ended December 31, 2016
	RSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	1,413		$	26.71
Granted	1,950		$	11.20
Vested and released	(607	)	$	25.01
Forfeited	(39	)	$	16.15
Outstanding at end of period	2,717		$	16.11

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

For RSUs, we consider the fair value to be the closing price of the stock on the grant date. The weighted average grant date fair value of RSUs granted during the years ended December 31, 2015 and 2014 was $28.93 and $23.36, respectively. We recognize the fair value of our share-based payments over the vesting periods of the awards, which is typically a three-year service period.

The following summarizes our PSU activity:

	Year Ended December 31, 2016
	PSUs (in thousands)		Weighted Average Grant Date Fair Value
Outstanding at beginning of period	576		$	25.22
Granted	769		$	11.04
Vested and released	(1	)	$	27.24
Forfeited	(123	)	$	23.35
Outstanding at end of period	1,221		$	16.48

The weighted average grant date fair value of PSUs granted during the years ended December 31, 2015 and 2014 was $27.54 and $23.03.

For PSUs granted prior to 2016, the fair value is determined using total shareholder return (“TSR”), measured over a three-year period relative to a selected group of energy industry peer companies, using a Monte Carlo model. The key characteristics of the PSUs are as follows:

· Three-year performance period;

· Payout opportunity of 0-200 percent of target (100 percent), intended to be settled in shares;

· Cumulative TSR percentile ranking calculated at end of performance period and applied to the payout scale to determine the number of earned/vested PSUs; and

· If absolute TSR is negative, PSU award payouts will be capped at 100 percent of the target number of PSUs granted, regardless of relative TSR positioning.

For PSUs granted in 2016, the fair value is determined using TSR for one-half of the award and the other half using pre-determined free cash flow (“FCF”) thresholds based upon the three year performance period. The FCF payout opportunity is also 0-200 percent of target (100 percent) intended to be settled in shares. These PSUs have the same key characteristics as described above.

Note 19—Employee Compensation, Savings, 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. During the years ended December 31, 2016, 2015 and 2014, our contributions related to these plans were approximately $43 million, $50 million and $37 million, respectively. The following summarizes these plans:

Short-Term Incentive Plan. Dynegy maintains a discretionary incentive compensation plan to provide our employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are determined by Dynegy’s Compensation and Human Resources Committee of the Board of Directors and are based on predetermined goals and objectives established at the start of each performance year.

Phantom Stock Plan. Dynegy has issued phantom stock units under its 2009 Phantom Stock Plan. Units awarded under this plan are long term incentive awards that grant the participant the right to receive a cash payment based on the fair market value of Dynegy’s stock on the vesting date of the award. As these awards must be settled in cash, we account for them as liabilities, with changes in the fair value of the liability recognized as expense in our consolidated statements of operations. Expense recognized in connection with these awards during the years ended December 31, 2016, 2015 and 2014 was $1 million, $1 million and $4 million, respectively.

Dynegy Inc. 401(k) Savings Plans. For the years ended December 31, 2016, 2015 and 2014, our employees participated in several 401(k) savings plans, all of which meet the requirements of IRC Section 401(k) and are defined contribution plans subject to the provisions of the Employee Retirement Income Security Act. Effective January 1, 2016, all of these plans, except for the Brayton Point Energy LLC 401k Plan for Bargaining Employees, were merged into the Dynegy 401(k) Plan and employees who participate in these plans became eligible to participate in the Dynegy 401(k) Plan. The following summarizes the plan:

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· Dynegy 401(k) Plan. This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the U.S. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in this plan. Except for certain represented employees, employee pre-tax and Roth contributions to the plan are matched by the Company at 100 percent, up to a maximum of five percent of base pay (subject to IRS limitations) and vesting in company contributions is based on years of service with 50 percent vesting per full year of service. This plan also allows for a discretionary contribution to eligible employee accounts for each plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2016.

During the years ended December 31, 2016, 2015 and 2014, we recognized aggregate costs related to our 401(k) Plans of $15 million, $10 million and $7 million, respectively.

Pension and Other Post-Employment Benefits

We have various defined benefit pension plans and post-employment benefit plans. Generally, all employees participate in the pension plans (subject to plan eligibility requirements), but only some of our employees participate in the other post-employment medical and life insurance benefit plans. The pension plans are in the form of cash balance plans and more traditional career average or final average pay formula plans. Separately, our EEI employees and retirees participate in EEI’s single-employer pension and other post-employment plans. We consolidate EEI, and therefore, EEI’s plans are reflected in our pension and post-employment balances and disclosures. Dynegy and EEI both use a measurement date of December 31 for their pension and post-employment benefit plans.

In the fourth quarter of 2016, EEI other post-employment plans were amended to change health benefits to a Health Reimbursement Account (“HRA”) for salaried employees and union employees. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans and recorded a net-of-tax gain of approximately $17 million through accumulated other comprehensive income.

In the fourth quarter of 2016, annuities and individual life insurance policies were purchased from the EEI other post-employment plans, relieving Dynegy of its obligation for the medical and life insurance coverage for inactive participants. As a result, we recorded a net-of-tax settlement cost of $6 million through operating and maintenance expense.

Obligations and Funded Status. The following tables contain information about the obligations, plan assets, and funded status of all plans in which we, or one of our subsidiaries, formerly sponsored or participated in on a combined basis.

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2016			2015
Benefit obligation, beginning of the year	$	483		$	408		$	74		$	95
Service cost	16			14			1			1
Interest cost	20			18			3			4
Actuarial (gain) loss	23			(20		)	4			(12		)
Benefits paid	(32		)	(26		)	(6		)	(5		)
Plan change	(2		)	—			(17		)	(10		)
Settlements	—			—			(17		)	(1		)
Acquisitions	—			89			—			2
Benefit obligation, end of the year	$	508		$	483		$	42		$	74
Fair value of plan assets, beginning of the year	$	410		$	364		$	67		$	68
Actual return on plan assets	37			(13		)	2			2
Employer contributions	—			4			—			—
Benefits paid	(32		)	(26		)	(3		)	(3		)
Settlements	—			—			(17		)	—
Acquisitions	—			81			—			—
Fair value of plan assets, end of the year	$	415		$	410		$	49		$	67
Funded status	$	(93	)	$	(73	)	$	7		$	(7	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Our accumulated benefit obligation related to pension plans was $501 million and $481 million as of December 31, 2016 and 2015, respectively. Our accumulated benefit obligation related to other post-employment plans was $42 million and $74 million as of December 31, 2016 and 2015, respectively.

Amounts recognized in the consolidated balance sheets consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2016			2015
Non-current assets	$	7		$	5		$	32		$	23
Current liabilities	—			—			(2		)	(2		)
Non-current liabilities	(100		)	(78		)	(23		)	(28		)
Net amount recognized	$	(93	)	$	(73	)	$	7		$	(7	)

Pre-tax amounts recognized in AOCI consist of:

	Pension Benefits						Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2016			2015
Prior service credit	$	(12	)	$	(11	)	$	(47	)	$	(34	)
Actuarial loss (gain)	2			(6		)	1			2
Net gain recognized	$	(10	)	$	(17	)	$	(46	)	$	(32	)

The net actuarial loss (gain) and prior service credit that were amortized from AOCI into net periodic benefit cost during the years ended December 31, 2016, 2015 and 2014 for the defined benefit pension plans were $1 million, $1 million and $2 million, respectively. The net prior service credit that was amortized from AOCI into net periodic benefit cost during the years ended December 31, 2016, 2015 and 2014 for other post-employment benefit plans was $4 million, $3 million and $3 million, respectively.

The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2017 are as follows:

(amounts in millions)	Pension Benefits			Other Benefits
Prior service credit	$	(1	)	$	(5	)
Actuarial (gain) loss	—			—
Net gain recognized	$	(1	)	$	(5	)

The amortization of prior service cost is determined using a straight line amortization of the cost over the average remaining service period of employees expected to receive benefits under the plans.

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

	Pension Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Service cost benefits earned during period	$	16		$	14		$	12
Interest cost on projected benefit obligation	20			18			17
Expected return on plan assets	(22		)	(23		)	(21		)
Amortization of:
Prior service credit	(1		)	(1		)	(1		)
Actuarial gain	—			—			(1		)
Net periodic benefit cost	$	13		$	8		$	6

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Other Benefits
	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Service cost benefits earned during period	$	1		$	1		$	1
Interest cost on projected benefit obligation	3			4			4
Expected return on plan assets	(4		)	(4		)	(4		)
Amortization of:
Prior service credit	(4		)	(3		)	(3		)
Net periodic benefit gain	(4		)	(2		)	(2		)
Settlement cost (1)	6			—			—
Total benefit cost (gain)	$	2		$	(2	)	$	(2	)

(1) The settlement cost for the year ended December 31, 2016 was related to EEI’s other post-employment benefit plan for EEI union employees.

Assumptions. The following weighted average assumptions were used to determine benefit obligations:

	Pension Benefits				Other Benefits
	Year Ended December 31,
	2016		2015		2016		2015
Discount rate (1)	4.05	%	4.35	%	4.00	%	4.35	%
Rate of compensation increase (2)	3.50	%	3.50	%	3.50	%	3.50	%

(1) We utilized a yield curve approach to determine the discount. Projected benefit payments for the plans were matched against the discount rates in the yield curve.

(2) The rate of compensation increase used for other post-employment benefits is specifically related to the EEI post-employment plans.

The following weighted average assumptions were used to determine net periodic benefit cost (gain):

	Pension Benefits						Other Benefits
	Year Ended December 31,
	2016		2015		2014		2016		2015		2014
Discount rate	4.05	%	4.35	%	4.00	%	4.00	%	4.35	%	4.00	%
Dynegy - Expected return on plan assets	5.60	%	5.70	%	6.00	%	N/A		N/A		N/A
EEI - Expected return on plan assets (1)	5.90	%	6.00	%	6.25	%	5.40	%	5.50	%	6.00	%
Rate of compensation increase (2)	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%	3.50	%

(1) The average expected return on EEI’s other post-employment plan assets was 5.40 percent, 5.50 percent, and 6 percent for the years ended December 31, 2016, 2015 and 2014, respectively. The expected return on EEI’s other post-employment plan assets was 6.30 percent, 6.20 percent, and 6.50 percent for EEI union employees for the years ended December 31, 2016, 2015 and 2014, respectively. The expected return on EEI’s other post-employment plan assets was 4.50 percent, 4.80 percent, and 5.50 percent for EEI salaried employees for the years ended December 31, 2016, 2015 and 2014, respectively.

(2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2016, 2015 and 2014 is specifically related to the EEI post-employment plans.

Our expected long-term rate of return on Dynegy’s pension plan assets and EEI’s pension plan assets is 6.20 percent and 6.40 percent, respectively, for the year ended December 31, 2017. Our expected long-term rate of return on EEI’s other post-employment plan assets is 6.90 percent for EEI union employees and 5.50 percent for EEI salaried employees for the year ended December 31, 2017. This figure begins with a blend of asset class-level returns developed under a theoretical global capital asset pricing model methodology conducted by an outside consultant. In development of this figure, the historical relationships between equities and fixed income are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Current market factors such as inflation and interest rates are also incorporated in the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

assumptions. This figure gives consideration towards the plan’s use of active management and favorable past experience. It is also net of plan expenses.

The following summarizes our assumed health care cost trend rates:

	Year Ended December 31,
	2016		2015		2014
Health care cost trend rate assumed for next year	7.25	%	7.00	%	7.25	%
Ultimate trend rate	4.50	%	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2025		2023		2023

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows:

(amounts in millions)	Increase		Decrease
Aggregate impact on service cost and interest cost	$	1	$	—
Impact on accumulated post-employment benefit obligation	$	3	$	(2	)

Plan Assets. We employ a total return investment approach whereby a mix of equity and fixed income investments are used to maximize the long-term return of plan assets for a prudent level of risk. The intent of this strategy is to minimize plan expenses by outperforming plan liabilities over the long run. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed income investments. Furthermore, equity investments are diversified across U.S. and non-U.S. stocks as well as growth, value, and small and large capitalizations. The Dynegy plans have adopted a glide-path approach to de-risk the portfolio as funding levels increased. The target asset mix as of December 31, 2016 was approximately 46 percent to equity investments and approximately 54 percent to fixed income investments. The target asset mix for EEI’s plan assets as of December 31, 2016 was approximately 60 percent to equity investments and approximately 40 percent to fixed income investments. EEI’s plan assets are routinely monitored and rebalanced as circumstances warrant.

Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives may not be used to leverage the portfolio beyond the market value of the underlying investment. Investment risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews, periodic asset/liability studies and annual liability measurements.

The following tables set forth by level within the fair value hierarchy assets that were accounted for at fair value related to our pension and other post-employment plans. These assets are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

	Fair Value as of December 31, 2016
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	4	$	2	$	—	$	6
Equity securities:
U.S. companies (1)	18		129		—		147
Non-U.S. companies (2)	1		15		—		16
International (3)	8		58		—		66
Fixed income securities (4)	70		161		—		231
Trust asset receivable (5)	—		—		—		—
Total	$	101	$	365	$	—	$	466

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

	Fair Value as of December 31, 2015
(amounts in millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	1	$	1	$	—	$	2
Equity securities:
U.S. companies (1)	32		125		—		157
Non-U.S. companies (2)	—		10		—		10
International (3)	8		54		—		62
Fixed income securities (4)	83		152		—		235
Trust asset receivable (5)	—		11		—		11
Total	$	124	$	353	$	—	$	477

(1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.

(2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.

(3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.

(4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

(5) Relates to the pension and other post-employment plans transferred to Dynegy as a result of the Acquisitions.

Contributions and Payments. We were required to make no contributions and $4 million in contributions to our pension plans and $2 million and no contributions to our other post-employment benefit plans during the years ended December 31, 2016 and 2015, respectively. We are required to make contributions of $4 million to our pension plans and $2 million to our other post-employment benefit plans during 2017.

Our expected benefit payments for future services for our pension and other post-employment benefits are as follows:

(amounts in millions)	Pension Benefits		Other Benefits
2017	$	35	$	4
2018	$	34	$	3
2019	$	35	$	3
2020	$	37	$	3
2021	$	37	$	3
2022 - 2026	$	193	$	13

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 20—Quarterly Financial Information

The following is a summary of our unaudited quarterly financial information:

	Quarter Ended
(amounts in millions, except per share data)	March 31			June 30			September 30			December 31
2016
Revenues	$	1,123		$	904		$	1,184		$	1,107
Operating income (loss) (1)	$	145		$	(702	)	$	(117	)	$	34
Net loss	$	(10	)	$	(803	)	$	(249	)	$	(182	)
Net loss attributable to Dynegy Inc. common stockholders	$	(15	)	$	(807	)	$	(254	)	$	(186	)
Net loss per share attributable to Dynegy Inc. common stockholders—Basic	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)
Net loss per share attributable to Dynegy Inc. common stockholders—Diluted	$	(0.13	)	$	(6.73	)	$	(1.81	)	$	(1.33	)
2015 (2)
Revenues	$	632		$	990		$	1,232		$	1,016
Operating income (loss) (3)	$	(40	)	$	10		$	107		$	(13	)
Net income (loss)	$	(181	)	$	386		$	(24	)	$	(134	)
Net income (loss) attributable to Dynegy Inc. common stockholders	$	(185	)	$	382		$	(29	)	$	(140	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic	$	(1.49	)	$	2.98		$	(0.23	)	$	(1.18	)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted	$	(1.49	)	$	2.73		$	(0.23	)	$	(1.18	)

(1) The results for the quarters ended June 30, 2016, September 30, 2016, and December 31, 2016, include impairment charges of $645 million, $212 million, and $1 million, respectively. See Note 9—Property, Plant and Equipment and Note 11—Unconsolidated Investments for more information.

(2) The unaudited quarterly information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 reflects the impact of the Acquisitions. Please read Note 3—Acquisitions for further discussion.

(3) The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million, respectively. See Note 9—Property, Plant and Equipment for more information.

Note 21—Condensed Consolidating Financial Information

Dynegy’s senior notes are guaranteed by certain of our wholly owned subsidiaries. Not all of Dynegy’s subsidiaries guaranteed the senior notes including Dynegy’s indirect, wholly owned subsidiary, IPH. The following condensed consolidating financial statements as of and for the year ended December 31, 2016 and 2015 present the financial information of (i) Dynegy (“Parent”), which is the parent and issuer of the senior 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 condensed consolidating financial statements for the year ended December 31, 2014 present the Escrow Issuers as the finance issuer of the $5.1 billion senior notes issued in October 2014. With the close of the Acquisitions, the Escrow Issuers were merged into Dynegy.

The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes.

These statements should be read in conjunction with the 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. On February 2, 2017, upon Genco’s emergence from bankruptcy, IPH became a guarantor to the senior notes.

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

F-51

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2016

(amounts in millions)

	Parent		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
Current Assets
Cash and cash equivalents	$	1,529	$	139		$	108		$	—		$	1,776
Restricted cash	—		—			62			—			62
Accounts receivable, net	141		2,539			136			(2,430		)	386
Inventory	—		236			209			—			445
Other current assets	12		275			32			(1		)	318
Total Current Assets	1,682		3,189			547			(2,431		)	2,987
Property, plant and equipment, net	—		6,593			528			—			7,121
Investment in affiliates	12,125		—			—			(12,125		)	—
Restricted cash	—		—			2,000			—			2,000
Goodwill	—		799			—			—			799
Other long-term assets	2		89			55			—			146
Intercompany note receivable	—		—			8			(8		)	—
Total Assets	$	13,809	$	10,670		$	3,138		$	(14,564	)	$	13,053
Current Liabilities
Accounts payable	$	1,914	$	295		$	553		$	(2,430	)	$	332
Other current liabilities	128		348			109			(1		)	584
Total Current Liabilities	2,042		643			662			(2,431		)	916
Liabilities subject to compromise	—		—			832			—			832
Debt, long-term portion, net	6,551		216			2,011			—			8,778
Intercompany note payable	3,042		—			—			(3,042		)	—
Other long-term liabilities	132		235			129			(8		)	488
Total Liabilities	11,767		1,094			3,634			(5,481		)	11,014
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,042		12,618			(493		)	(12,125		)	2,042
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,042		9,576			(493		)	(9,083		)	2,042
Noncontrolling interest	—		—			(3		)	—			(3		)
Total Equity	2,042		9,576			(496		)	(9,083		)	2,039
Total Liabilities and Equity	$	13,809	$	10,670		$	3,138		$	(14,564	)	$	13,053

F-52

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Balance Sheet for the Year Ended December 31, 2015

(amounts in millions)

	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		1,292			130			(1,519		)	402
Inventory	—		326			271			—			597
Other current assets	13		322			68			(14		)	389
Total Current Assets	839		2,034			592			(1,533		)	1,932
Property, plant and equipment, net	—		7,670			677			—			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	$	10,824		$	1,319		$	(14,567	)	$	11,459
Current Liabilities
Accounts payable	$	1,388	$	234		$	189		$	(1,519	)	$	292
Other current liabilities	92		272			167			(14		)	517
Total Current Liabilities	1,480		506			356			(1,533		)	809
Debt, long-term portion, net	6,293		105			731			—			7,129
Intercompany note payable	3,042		—			17			(3,059		)	—
Other long-term liabilities	147		317			138			—			602
Total Liabilities	10,962		928			1,242			(4,592		)	8,540
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,921		12,938			79			(13,017		)	2,921
Intercompany note receivable	—		(3,042		)	—			3,042			—
Total Dynegy Stockholders’ Equity	2,921		9,896			79			(9,975		)	2,921
Noncontrolling interest	—		—			(2		)	—			(2		)
Total Equity	2,921		9,896			77			(9,975		)	2,919
Total Liabilities and Equity	$	13,883	$	10,824		$	1,319		$	(14,567	)	$	11,459

F-53

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,317		$	1,093		$	(92	)	$	4,318
Cost of sales, excluding depreciation expense	—			(1,737		)	(636		)	92			(2,281		)
Gross margin	—			1,580			457			—			2,037
Operating and maintenance expense	—			(637		)	(303		)	—			(940		)
Depreciation expense	—			(590		)	(99		)	—			(689		)
Impairments	—			(710		)	(148		)	—			(858		)
Gain on sale of assets, net	(2		)	—			1			—			(1		)
General and administrative expense	(7		)	(117		)	(37		)	—			(161		)
Acquisition and integration costs	(10		)	(3		)	2			—			(11		)
Other	—			(1		)	(16		)	—			(17		)
Operating loss	(19		)	(478		)	(143		)	—			(640		)
Bankruptcy reorganization items	—			—			(96		)	—			(96		)
Earnings from unconsolidated investments	—			7			—			—			7
Equity in losses from investments in affiliates	(765		)	—			—			765			—
Interest expense	(485		)	(10		)	(132		)	2			(625		)
Other income and expense, net	29			20			18			(2		)	65
Loss before income taxes	(1,240		)	(461		)	(353		)	765			(1,289		)
Income tax benefit (expense) (Note 15)	—			86			(41		)	—			45
Net loss	(1,240		)	(375		)	(394		)	765			(1,244		)
Less: Net loss attributable to noncontrolling interest	—			—			(4		)	—			(4		)
Net loss attributable to Dynegy Inc.	$	(1,240	)	$	(375	)	$	(390	)	$	765		$	(1,240	)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	2,713		$	1,161		$	(4	)	$	3,870
Cost of sales, excluding depreciation expense	—			(1,322		)	(710		)	4			(2,028		)
Gross margin	—			1,391			451			—			1,842
Operating and maintenance expense	—			(549		)	(290		)	—			(839		)
Depreciation expense	—			(487		)	(100		)	—			(587		)
Impairments	—			(74		)	(25		)	—			(99		)
Loss on sale of assets, net	—			(1		)	—			—			(1		)
General and administrative expense	(6		)	(91		)	(31		)	—			(128		)
Acquisition and integration costs	—			(124		)	—			—			(124		)
Operating income (loss)	(6		)	65			5			—			64
Earnings from unconsolidated investments	—			1			—			—			1
Equity in earnings from investments in affiliates	476			—			—			(476		)	—
Interest expense	(475		)	(1		)	(70		)	—			(546		)
Other income and expense, net	55			(1		)	—			—			54
Income (loss) before income taxes	50			64			(65		)	(476		)	(427		)
Income tax benefit (Note 15)	—			471			3			—			474
Net income (loss)	50			535			(62		)	(476		)	47
Less: Net loss attributable to noncontrolling interest	—			—			(3		)	—			(3		)
Net income (loss) attributable to Dynegy Inc.	$	50		$	535		$	(59	)	$	(476	)	$	50

F-54

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Operations for the Year Ended December 31, 2014

(amounts in millions)

	Parent			Escrow Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	—		$	1,184		$	1,313		$	—		$	2,497
Cost of sales, excluding depreciation expense	—			—			(702		)	(959		)	—			(1,661		)
Gross margin	—			—			482			354			—			836
Operating and maintenance expense	—			—			(258		)	(219		)	—			(477		)
Depreciation expense	—			—			(195		)	(52		)	—			(247		)
Gain on sale of assets, net	—			—			18			—			—			18
General and administrative expense	(9		)	—			(60		)	(45		)	—			(114		)
Acquisition and integration costs	—			—			(19		)	(16		)	—			(35		)
Operating income (loss)	(9		)	—			(32		)	22			—			(19		)
Bankruptcy reorganization items	3			—			—			—			—			3
Earnings from unconsolidated investments	—			—			10			—			—			10
Equity in losses from investments in affiliates	(131		)	—			—			—			131			—
Interest expense	(89		)	(67		)	—			(68		)	1			(223		)
Other income and expense, net	(39		)	—			1			—			(1		)	(39		)
Loss before income taxes	(265		)	(67		)	(21		)	(46		)	131			(268		)
Income tax benefit (expense) (Note 15)	(8		)	—			—			9			—			1
Net loss	(273		)	(67		)	(21		)	(37		)	131			(267		)
Less: Net income attributable to noncontrolling interest	—			—			—			6			—			6
Net loss attributable to Dynegy Inc.	$	(273	)	$	(67	)	$	(21	)	$	(43	)	$	131		$	(273	)

Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net loss	$	(1,240	)	$	(375	)	$	(394	)	$	765		$	(1,244	)
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of $3	(4		)	1			6			—			3
Amounts reclassified from accumulated other comprehensive income:
Settlement cost, net of tax of zero	—			—			6			—			6
Amortization of unrecognized prior service credit, net of tax of zero	(4		)	—			(1		)	—			(5		)
Other comprehensive income from investment in affiliates	12			—			—			(12		)	—
Other comprehensive income, net of tax	4			1			11			(12		)	4
Comprehensive loss	(1,236		)	(374		)	(383		)	753			(1,240		)
Less: Comprehensive income (loss) attributable to noncontrolling interest	2			—			(2		)	(2		)	(2		)
Total comprehensive loss attributable to Dynegy Inc.	$	(1,238	)	$	(374	)	$	(381	)	$	755		$	(1,238	)

F-55

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2015

(amounts in millions)

	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	50		$	535	$	(62	)	$	(476	)	$	47
Other comprehensive income (loss) before reclassifications:
Actuarial gain (loss) and plan amendments, net of tax of zero	(8		)	2		10			—			4
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(3		)	—		(1		)	—			(4		)
Other comprehensive loss from investment in affiliates	11			—		—			(11		)	—
Other comprehensive income, net of tax	—			2		9			(11		)	—
Comprehensive income (loss)	50			537		(53		)	(487		)	47
Less: Comprehensive income (loss) attributable to noncontrolling interest	1			—		(2		)	(1		)	(2		)
Total comprehensive income (loss) attributable to Dynegy Inc.	$	49		$	537	$	(51	)	$	(486	)	$	49

Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2014

(amounts in millions)

	Parent			Escrow Issuers			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(273	)	(67		)	$	(21	)	$	(37	)	$	131		$	(267	)
Other comprehensive income before reclassifications:
Actuarial loss and plan amendments, net of tax of zero	(20		)	—			—			(16		)	—			(36		)
Amounts reclassified from accumulated other comprehensive income (loss):
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(5		)	—			—			—			—			(5		)
Other comprehensive loss from investment in affiliates	(16		)	—			—			—			16			—
Other comprehensive loss, net of tax	(41		)	—			—			(16		)	16			(41		)
Comprehensive income (loss)	(314		)	(67		)	(21		)	(53		)	147			(308		)
Less: comprehensive income attributable to noncontrolling interest	3			—			—			3			(3		)	3
Total comprehensive income (loss) attributable to Dynegy Inc.	$	(317	)	$	(67	)	$	(21	)	$	(56	)	$	150		$	(311	)

F-56

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2016

(amounts in millions)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(425	)	$	1,057		$	13		$	—		$	645
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(215		)	(78		)	—			(293		)
Distributions from unconsolidated affiliate	—			14			—			—			14
Proceeds from sales of assets, net	171			2			3			—			176
Net intercompany transfers	880			—			—			(880		)	—
Other investing	—			10			—			—			10
Net cash provided by (used in) investing activities	1,051			(189		)	(75		)	(880		)	(93		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	822			198			1,994			—			3,014
Repayments of borrowings	(563		)	(15		)	(11		)	—			(589		)
Proceeds from issuance of equity, net of issuance costs	359			—			—			—			359
Preferred stock dividends paid	(22		)	—			—			—			(22		)
Interest rate swap settlement payments	(17		)	—			—			—			(17		)
Net intercompany transfers	—			(1,006		)	126			880			—
Other financing	(3		)	—			—			—			(3		)
Net cash provided by (used in) financing activities	576			(823		)	2,109			880			2,742
Net increase in cash, cash equivalents, and restricted cash	1,202			45			2,047			—			3,294
Cash, cash equivalents, and restricted cash, beginning of period	327			94			123			—			544
Cash, cash equivalents, and restricted cash, end of period	$	1,529		$	139		$	2,170		$	—		$	3,838

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 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	$	(432	)	$	531		$	(5	)	$	—		$	94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			(235		)	(66		)	—			(301		)
Acquisitions, net of cash acquired	(6,207		)	29			100			—			(6,078		)
Distributions from unconsolidated affiliate	—			8			—			—			8
Net intercompany transfers	450			—			—			(450		)	—
Other investing	—			3			—			—			3
Net cash provided by (used in) investing activities	(5,757		)	(195		)	34			(450		)	(6,368		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	(31		)	78			19			—			66
Repayments of borrowings	(8		)	(23		)	—			—			(31		)
Proceeds from issuance of equity, net of issuance costs	(6		)	—			—			—			(6		)
Preferred stock dividends paid	(23		)	—			—			—			(23		)
Interest rate swap settlement payments	(17		)	—			—			—			(17		)
Repurchase of common stock	(250		)	—			—			—			(250		)
Net intercompany transfers	—			(351		)	(99		)	450			—
Other financing	(4		)	—			—			—			(4		)
Net cash provided by (used in) financing activities	(339		)	(296		)	(80		)	450			(265		)
Net increase in cash, cash equivalents, and restricted cash	(6,528		)	40			(51		)	—			(6,539		)
Cash, cash equivalents, and restricted cash, beginning of period	6,855			54			174			—			7,083
Cash, cash equivalents, and restricted cash, end of period	$	327		$	94		$	123		$	—		$	544

F-57

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2014

(amounts in millions)

	Parent			Escrow Issuers		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(70	)	$	3	$	189		$	99		$	—		$	221
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	—			—		(75		)	(50		)	—			(125		)
Proceeds from sales of assets, net	—			—		18			—			—			18
Net intercompany transfers	162			—		—			—			(162		)	—
Net cash provided by (used in) investing activities	162			—		(57		)	(50		)	(162		)	(107		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	(1		)	5,044		12			—			—			5,055
Repayments of borrowings	(8		)	—		(6		)	—			—			(14		)
Proceeds from issuance of equity, net of issuance costs	1,106			—		—			—			—			1,106
Interest rate swap settlement payments	(18		)	—		—			—			—			(18		)
Net intercompany transfers	—			166		(238		)	(90		)	162			—
Other financing	(3		)	—		—			—			—			(3		)
Net cash provided by (used in) financing activities	1,076			5,210		(232		)	(90		)	162			6,126
Net increase in cash, cash equivalents, and restricted cash	1,168			5,213		(100		)	(41		)	—			6,240
Cash, cash equivalents, and restricted cash, beginning of period	474			—		154			215			—			843
Cash, cash equivalents, and restricted cash, end of period	$	1,642		$	5,213	$	54		$	174		$	—		$	7,083

Note 22—Genco Chapter 11 Bankruptcy

On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes either through (a) out-of-court exchanges (the “Exchange Offer”) or (b) if the Exchange Offer was not successful, the Genco Plan. Under the RSA, the $825 million of existing Genco Senior Notes were to be exchanged for up to $210 million in new seven-year Dynegy unsecured notes, up to $139 million of cash consideration (including a $9 million RSA payment, as described below (the “RSA Payment”)) funded with existing IPH cash balances and an expected return of collateral of approximately $61 million, and up to 10 million of Dynegy warrants with a seven-year term for an exercise price of $35 per share. Dynegy, Genco, and the Ad Hoc Group agreed that holders of the Genco Senior Notes who entered into the RSA on or before October 21, 2016, would be paid their pro rata share of the RSA Payment in cash upon consummation of a restructuring, with such pro rata share determined as the proportion that the amount of Genco Senior Notes held by each such holder bears to the aggregate amount of Genco Senior Notes held by all holders entitled to receive a share of the RSA Payment. Genco made its interest payment that was due on December 1, 2016 and such payment was netted against the cash consideration.

The Exchange Offer was launched in November 2016 and on December 9, 2016, Dynegy and Genco announced (i) that they received the required number and amount of votes in favor of the Genco Plan, (ii) that Genco subsequently filed the Bankruptcy Petition for reorganization under the Bankruptcy Code in the Bankruptcy Court, and (iii) that the previously announced Exchange Offer was terminated because the required participation threshold of 97 percent of the aggregate principal amount of Genco Senior Notes was not satisfied. Genco continued to operate its business as “debtor-in possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court until the Emergence Date. On the Emergence Date, we exchanged $757 million of these Genco Senior notes for $113 million of cash, $182 million of new Dynegy seven year unsecured notes, and warrants to purchase up to 8.7 million of common stock for an exercise price of $35 per share (the “2017 Warrants”). The 2017 Warrants have a seven-year term expiring on February 2, 2024. Holders of Genco Senior Notes who did not receive a distribution under the Genco Plan on the Emergence Date have until July 17, 2017 (the 165th day after the Emergence Date) in order to exercise their rights to receive a distribution.

The filing of the prepackaged Chapter 11 Case constituted or may have constituted an event of default or otherwise triggered or may have triggered repayment obligations under the express terms of certain instruments and agreements relating to direct financial obligations of Genco or obligations under off-balance sheet arrangements (the “Debt Documents”). As a result of such an event of default or triggering event, all obligations under the Debt Documents, by terms of the Debt Documents, have or may have become due and payable, but were subject to the provisions of the Bankruptcy Code. Such event of default would not be an event of default for Dynegy’s other indebtedness, as the Genco Senior Notes were nonrecourse to Dynegy. The material Debt Documents are the Genco Senior Notes.

F-58

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Condensed Balance Sheet As of December 31, 2016

(amounts in millions)	Genco, as Debtor-in- Possession			Intercompany Eliminations			Amounts included in Dynegy’s Consolidated Financial Statements
Cash	$	49		$	—		$	49
Intercompany and affiliate receivables	184			(184		)	—
Other current assets	76			—			76
Property, plant & equipment	59			—			59
Other non-current assets	3			—			3
Total Assets	$	371		$	(184	)	$	187

Current liabilities	$	64		$	(31	)	$	33
Liabilities subject to compromise	832			—			832
Asset retirement obligations	37			—			37
Other non-current liabilities	5			(5		)	—
Total Liabilities	$	938		$	(36	)	$	902

Total stockholder deficit	$	(552	)	$	(148	)	(700		)
Noncontrolling Interest	(15		)	—			(15		)
Total Deficit	$	(567	)	$	(148	)	$	(715	)

Total Liabilities and Deficit	$	371		$	(184	)	$	187

Condensed Statement of Operations and Comprehensive Loss

For the Period from December 10, 2016 to December 31, 2016

(amounts in millions)	Genco, as Debtor-in- Possession			Intercompany Eliminations			Amounts included in Dynegy’s Consolidated Financial Statements
Revenues	$	19		$	(19	)	$	—
Cost of sales, excluding depreciation expense	(11		)	—			(11		)
Gross margin	8			(19		)	(11		)
Operating and maintenance expense	(6		)	—			(6		)
Other operating costs	(4		)	1			(3		)
Operating loss	(2		)	(18		)	(20		)
Bankruptcy reorganization items	(96		)	—			(96		)
Net loss attributable to Stockholder	(98		)	(18		)	(116		)
Other Comprehensive loss, net of tax	—			—			—
Comprehensive loss	$	(98	)	$	(18	)	$	(116	)

Condensed Statement of Cash Flows

For the Period from December 10, 2016 to December 31, 2016

(amounts in millions)	Genco, as Debtor-in- Possession		Intercompany Eliminations		Amounts included in Dynegy’s Consolidated Financial Statements
Net cash provided by operating activities	$	3	$	—	$	3
Net increase in cash and cash equivalents	3		—		3
Cash and cash equivalents, beginning of period	46		—		46
Cash and cash equivalents, end of period	$	49	$	—	$	49

F-60

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Note 23—Segment Information

In the fourth quarter of 2016, Dynegy changed its organizational structure to manage its assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. As of December 31, 2016, we modified our reportable segments from a fuel-based segment structure to the following market areas: (i) PJM, (ii) NY/NE, (iii) MISO, (iv) IPH and (v) CAISO. The Company has recast data from prior periods to reflect this change in reportable segments to conform to the current year presentation. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. The IPH segment includes Genco, and Illinois Power Resources Generating, LLC (“IPRG”), which also own, directly and indirectly, certain of our coal-fired power generation facilities, which are all in MISO. IPH also includes our Homefield Energy retail business in Illinois. 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 years ended December 31, 2016, 2015 and 2014 is presented below:

Segment Data as of and for the Year Ended December 31, 2016

(amounts in millions)

	PJM			NY/NE			MISO			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	2,147		$	836		$	410		$	755		$	142		$	—		$	4,290
Intercompany and affiliate revenues	55			1			(27		)	(1		)	—			—			28
Total revenues	$	2,202		$	837		$	383		$	754		$	142		$	—		$	4,318

Depreciation expense	$	(346	)	$	(215	)	$	(49	)	$	(32	)	$	(42	)	$	(5	)	$	(689	)
Impairments	(65		)	—			(645		)	(148		)	—			—			(858		)
Gain on sale of assets, net	—			—			—			1			—			(2		)	(1		)
General and administrative expense	—			—			—			—			—			(161		)	(161		)
Acquisition and integration costs	—			—			—			8			—			(19		)	(11		)

Operating income (loss)	$	414		$	(29	)	$	(745	)	$	(87	)	$	(5	)	$	(188	)	$	(640	)

Bankruptcy reorganization items	—			—			—			(96		)	—			—			(96		)
Earnings from unconsolidated investments	7			—			—			—			—			—			7
Interest expense	—			—			—			—			—			(625		)	(625		)
Other income and expense, net	9			1			—			15			12			28			65
Loss before income taxes																			(1,289		)
Income tax expense	—			—			—			—			—			45			45
Net loss																			(1,244		)
Less: Net loss attributable to noncontrolling interest																			(4		)
Net loss attributable to Dynegy Inc.																			$	(1,240	)

Total assets—domestic	$	4,939		$	2,769		$	352		$	713		$	485		$	3,795		$	13,053
Capital expenditures	$	(160	)	$	(64	)	$	(12	)	$	(40	)	$	(7	)	$	(10	)	$	(293	)

F-61

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Segment Data as of and for the Year Ended December 31, 2015

(amounts in millions)

	PJM			NY/NE			MISO			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	1,708		$	705		$	475		$	804		$	178		$	—		$	3,870
Intercompany revenues	8			(10		)	7			(5		)	—			—			—
Total revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870

Depreciation expense	$	(281	)	$	(186	)	$	(39	)	$	(29	)	$	(48	)	$	(4	)	$	(587	)
Impairments	—			(25		)	(74		)	—			—			—			(99		)
Gain on sale of assets, net	—			—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			—			(124		)	(124		)

Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64

Earnings from unconsolidated investments	1			—			—			—			—			—			1
Interest expense	—			—			—			—			—			(546		)	(546		)
Other income and expense, net	(2		)	—			1			—			—			55			54
Loss before income taxes																			(427		)
Income tax benefit	—			—			—			—			—			474			474
Net income																			47
Less: Net loss attributable to noncontrolling interest																			(3		)
Net income attributable to Dynegy Inc.																			$	50

Total assets—domestic	$	5,474		$	2,970		$	1,098		$	897		$	534		$	486		$	11,459
Investment in unconsolidated affiliate	$	190		$	—		$	—		$	—		$	—		$	—		$	190
Capital expenditures	$	(106	)	$	(52	)	$	(56	)	$	(63	)	$	(11	)	$	(13	)	$	(301	)

F-62

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Segment Data as of and for the Year Ended December 31, 2014

(amounts in millions)

	PJM			NY/NE			MISO			IPH			CAISO			Other and Eliminations			Total
Domestic:
Unaffiliated revenues	$	340		$	466		$	584		$	850		$	257		$	—		$	2,497
Intercompany revenues	(9		)	(9		)	21			(4		)	1			—			—
Total revenues	$	331		$	457		$	605		$	846		$	258		$	—		$	2,497

Depreciation expense	$	(84	)	$	(26	)	$	(51	)	$	(37	)	$	(44	)	$	(5	)	$	(247	)
Gain on sale of assets, net	—			—			—			—			1			17			18
General and administrative expense	—			—			—			—			—			(114		)	(114		)
Acquisition and integration costs	—			—			—			(16		)	—			(19		)	(35		)

Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)

Bankruptcy reorganization items	—			—			—			—			—			3			3
Earnings from unconsolidated investments	—			—			—			—			—			10			10
Interest expense	—			—			—			—			—			(223		)	(223		)
Other income and expense, net	—			—			—			—			—			(39		)	(39		)
Loss from continuing operations before income taxes																			(268		)
Income tax benefit	—			—			—			—			—			1			1
Net loss																			(267		)
Less: Net income attributable to noncontrolling interest																			6
Net loss attributable to Dynegy Inc.																			$	(273	)

Total assets—domestic	$	1,055		$	363		$	1,166		$	1,039		$	584		$	6,947		$	11,154
Capital expenditures	$	(12	)	$	(7	)	$	(39	)	$	(45	)	$	(18	)	$	(4	)	$	(125	)

Significant Customers

Our total revenues for customers who individually accounted for more than 10 percent of our consolidated revenues, and the segments impacted, for the years ended December 31, 2016, 2015 and 2014 are presented below:

(amounts in millions)	Revenues
Customers	2016		2015		2014		Segment(s)
PJM	$	1,366	$	1,088	N/A		PJM, IPH
MISO	$	688	$	842	$	836	MISO, IPH
ISO-NE	$	437	N/A		N/A		NY/NE
NYISO	N/A		N/A		$	342	NY/NE

Employee Concentrations

As of December 31, 2016, approximately 49% of our employees are covered by a collective bargaining agreement.

Note 24—Subsequent Events

Delta Transaction. On February 7, 2017 (the “Delta Transaction Closing Date”), pursuant to the terms of the stock purchase agreement, Dynegy acquired approximately 9,017 MW of generation from GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “Delta Transaction”). On February 2, 2017, FERC issued an order accepting the December 27, 2016 Compliance

F-63

DYNEGY INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

Filing of Atlas Power Finance, LLC, Dynegy, and ECP (collectively, “Applicants”), which proposed mitigation measures in response to market power concerns identified by FERC in its December 22, 2016 order conditionally authorizing the Delta Transaction. In this order, FERC accepted, among other commitments, Applicants’ proposal to divest at least 224 MW in the SENE capacity zone in ISO-NE. Additionally, Dynegy paid Energy Capital Partners (“ECP”) $375 million (the “ECP Buyout Price”).

We incurred acquisition costs of $5 million for the year ended December 31, 2016, related to the Delta Transaction, which are included in Acquisition and integration costs in our consolidated statement of operations.

We are currently in the process of valuing the assets acquired and liabilities assumed in the Delta Transaction. We are currently unable to provide pro forma financial results or the amounts recognized for the major classes of assets acquired and liabilities assumed in the Delta Transaction as of the Delta Transaction Closing Date. We will provide these disclosures in our quarterly report on Form 10-Q for the first quarter of 2017.

Stock Purchase Agreement-Terawatt. On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the ECP Funds (the “PIPE Stock Purchase Agreement”), pursuant to which at the Delta Transaction Closing Date, Dynegy issued to Terawatt 13,711,152 shares (the “PIPE Shares”) of Dynegy common stock for $150 million (the “PIPE Transaction”). In connection with the closing of the PIPE Transaction, Dynegy and Terawatt entered into an Investor Rights Agreement, (the “Investor Rights Agreement”). Under the Investor Rights Agreement, Terawatt is entitled to certain rights, including certain registration rights, rights of first refusal with respect to certain issuances of our equity 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.

Credit Agreement Amendments

Third Amendment. On June 27, 2016, we entered into the Third Amendment to the Credit Agreement which provided, upon the Escrow Release Date relating to the Escrow Agreement described in Note 14—Debt, for (1) a $75 million increase to the Revolving Facility, which will mature on April 2, 2020 and (2) upon the merger of Finance IV with and into Dynegy, a $2.0 billion, seven-year senior secured Tranche C Term Loan with terms substantially the same as the Finance IV Credit Agreement.

Fourth Amendment. On January 10, 2017, we entered into the Fourth Amendment to the Credit Agreement which was effective upon the Delta Transaction Closing Date. The Fourth Amendment provided that, among other things, (1) the Initial Revolving Loan Maturity Date (as defined in the Existing Credit Agreement), with respect to certain of the Initial Revolving Loan Commitments (as defined in the Existing Credit Agreement), will be extended from April 23, 2018 to April 23, 2021 (the “Extended Maturity Date” and such extended Initial Revolving Loan Commitments, the “Extended Revolving Loan Commitments”), and (2) the tranche of Extended Revolving Loan Commitments will increase in an aggregate principal amount of $45 million.

Fifth Amendment. Upon the Delta Transaction Closing Date, we entered into the Fifth Amendment to the Credit Agreement which provided that, among other things, (1) the interest rate applicable to the Tranche C Term Loans was reduced by 75 basis points through the exchange of the Tranche C Term Loans for Tranche C-1 Term Loans otherwise having the same terms (except as otherwise provided in the Fifth Amendment) as the Tranche C Term Loans, and (2) the extension of the maturity to 2024 of the existing Tranche B-2 Term Loans through the exchange of the outstanding Initial Tranche B-2 Term Loans for Tranche C-1 Term Loans.

Letter of Credit Facilities

Following the Delta Transaction Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide letters of credit in an amount not to exceed $50 million. The facility has a one-year tenor and may be extended at the Lender’s discretion for up to four additional one-year terms.

Asset Sales

On February 23, 2017, Dynegy reached an agreement with LS Power for the sale of two peaking facilities in PJM for $480 million in cash. The assets to be sold, which were recently acquired in the Delta Transaction, include the Armstrong and Troy facilities totaling 1,269 MW. The sale is expected to close in the second half of 2017 with the proceeds to be allocated to debt reduction.

F-64

	Page
Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets:
December 31, 2016 and 2015	F-4
Consolidated Statements of Operations:
For the years ended December 31, 2016, 2015 and 2014	F-6
Consolidated Statements of Comprehensive Income (Loss):
For the years ended December 31, 2016, 2015 and 2014	F-7
Consolidated Statements of Cash Flows:
For the years ended December 31, 2016, 2015 and 2014	F-8
Consolidated Statements of Changes in Equity:
For the years ended December 31, 2016, 2015 and 2014	F-9
Notes to Consolidated Financial Statements	F-10

(amounts in millions)	December 31, 2016
Genco Senior Notes:
7.00% Senior Notes Series H, due 2018	$	300
6.30% Senior Notes Series I, due 2020	250
7.95% Senior Notes Series F, due 2032	275
Interest accrued	7
Total Liabilities subject to compromise	$	832

/s/ Ernst & Young LLP


Houston, Texas
February 24, 2017

/s/ Ernst & Young LLP

Houston, Texas