Dyne Therapeutics 10-K 22 Feb 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2017	Feb. 08, 2018	Jun. 30, 2017
Document and Entity Information [Abstract]
Entity Registrant Name	DYNEGY INC.
Entity Central Index Key	1,379,895
Document Type	10-K
Document Period End Date	Dec. 31, 2017
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float			$ 918,348,807
Entity Common Stock, Shares Outstanding		144,390,952
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 365	$ 1,776
Restricted cash	0	62
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	513	386
Inventory	445	445
Assets from risk management activities	32	130
Intangible assets	25	38
Prepayments and other current assets	144	150
Total Current Assets	1,524	2,987
Property, plant and equipment, net	8,884	7,121
Investment in unconsolidated affiliate	123	0
Restricted cash	0	2,000
Assets from risk management activities	26	16
Goodwill	772	799
Intangible assets	39	23
Other long-term assets	403	107
Total Assets	11,771	13,053
Current Liabilities
Accounts payable	367	332
Accrued interest	115	81
Intangible liabilities	14	21
Accrued taxes	64	45
Accrued liabilities and other current liabilities	109	88
Liabilities from risk management activities	229	97
Asset retirement obligations	46	51
Debt, current portion, net	105	201
Total Current Liabilities	1,049	916
Liabilities subject to compromise (Note 20)	0	832
Debt, long-term portion, net	8,328	8,778
Other Liabilities
Liabilities from risk management activities	31	43
Asset retirement obligations	283	236
Deferred income taxes	7	5
Intangible liabilities	34	34
Other long-term liabilities	146	170
Total Liabilities	9,878	11,014
Commitments and Contingencies (Note 16)
Stockholders’ Equity
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding at December 31, 2016	0	400
Common stock, $0.01 par value, 420,000,000 shares authorized; 155,710,613 shares issued and 144,384,491 shares outstanding at December 31, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016	1	1
Additional paid-in capital	3,719	3,547
Accumulated other comprehensive income, net of tax	32	21
Accumulated deficit	(1,851)	(1,927)
Total Dynegy Stockholders’ Equity	1,901	2,042
Noncontrolling interest	(8)	(3)
Total Equity	1,893	2,039
Total Liabilities and Equity	$ 11,771	$ 13,053

CONSOLIDATED BALANCE SHEETS (PA

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 1	$ 1
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (in shares)	20,000,000	20,000,000
Preferred stock, dividend rate	5.375%	5.375%
Preferred stock, shares issued (in shares)	0	4,000,000
Preferred stock, shares outstanding (in shares)	0	4,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	420,000,000	420,000,000
Common stock, shares issued (in shares)	155,710,613	128,626,740
Common stock, shares outstanding (in shares)	144,384,491	117,300,618

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Statement [Abstract]
Revenues	$ 4,842	$ 4,318	$ 3,870
Cost of sales, excluding depreciation expense	(2,932)	(2,281)	(2,028)
Gross margin	1,910	2,037	1,842
Operating and maintenance expense	(995)	(940)	(839)
Depreciation expense	(811)	(689)	(587)
Impairments	(148)	(858)	(99)
Loss on sale of assets, net	(122)	(1)	(1)
General and administrative expense	(189)	(161)	(128)
Acquisition and integration costs	(57)	(11)	(124)
Other	0	(17)	0
Operating income (loss)	(412)	(640)	64
Bankruptcy reorganization items (Note 20)	494	(96)	0
Earnings from unconsolidated investments	8	7	1
Interest expense	(616)	(625)	(546)
Loss on early extinguishment of debt (Note 13)	(79)	0	0
Other income and expense, net	67	65	54
Loss before income taxes	(538)	(1,289)	(427)
Income tax benefit (Note 14)	610	45	474
Net income (loss)	72	(1,244)	47
Less: Net loss attributable to noncontrolling interest	(4)	(4)	(3)
Net income (loss) attributable to Dynegy Inc.	76	(1,240)	50
Less: Dividends on preferred stock	18	22	22
Net income (loss) attributable to Dynegy Inc. common stockholders	$ 58	$ (1,262)	$ 28
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders:
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	$ 0.37	$ (9.78)	$ 0.22
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	$ 0.36	$ (9.78)	$ 0.22
Basic shares outstanding (in shares)	155	129	125
Diluted shares outstanding (in shares)	162	129	126

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (95)	$ (133)	$ (296)	$ 596	$ (182)	$ (249)	$ (803)	$ (10)	$ 72	$ (1,244)	$ 47
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)									19	3	4
Amounts reclassified from accumulated other comprehensive income:
Settlement cost (net of tax of zero)									0	6	0
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)									(8)	(5)	(4)
Other comprehensive income, net of tax									11	4	0
Comprehensive income (loss)									83	(1,240)	47
Less: Comprehensive loss attributable to noncontrolling interest									(4)	(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.									$ 87	$ (1,238)	$ 49

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (PARENTHETICAL) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other comprehensive income before reclassifications:
Actuarial gain and plan amendments, tax	$ 5	$ 3	$ 0
Amounts reclassified from accumulated other comprehensive income:
Settlement cost, tax	0	0	0
Amortization of unrecognized prior service credit and actuarial gain, tax	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 72	$ (1,244)	$ 47
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	811	689	587
Loss on early extinguishment of debt	79	0	0
Non-cash interest expense	44	56	38
Amortization of intangibles	12	21	(11)
Bankruptcy reorganization items	(494)	96	0
Impairments	148	858	99
Risk management activities	207	(148)	(130)
Loss on sale of assets, net	122	1	1
Earnings from unconsolidated investments	(8)	(7)	(1)
Deferred income taxes	(610)	(45)	(477)
Change in value of common stock warrants	(16)	(6)	(54)
Other	81	14	51
Changes in working capital:
Accounts receivable, net	(47)	42	(64)
Inventory	110	154	(119)
Prepayments and other current assets	26	94	94
Accounts payable and accrued liabilities	46	84	25
Distributions from unconsolidated investments	5	1	3
Changes in non-current assets	(12)	(43)	0
Changes in non-current liabilities	9	28	5
Net cash provided by operating activities	585	645	94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(224)	(293)	(301)
Acquisitions, net of cash acquired	(3,319)	0	(6,078)
Distributions from unconsolidated investments	12	14	8
Proceeds from asset sales, net	772	176	0
Other investing	0	10	3
Net cash used in investing activities	(2,759)	(93)	(6,368)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,743	3,014	66
Repayments of borrowings	(2,589)	(589)	(31)
Proceeds from issuance of equity, net of issuance costs	150	359	(6)
Payments of debt extinguishment costs	(50)	0	0
Preferred stock dividends paid	(22)	(22)	(23)
Interest rate swap settlement payments	(20)	(17)	(17)
Acquisition of noncontrolling interest	(375)	0	0
Payments related to bankruptcy settlement	(133)	0	0
Repurchase of common stock	0	0	(250)
Other financing	(3)	(3)	(4)
Net cash provided by (used in) financing activities	(1,299)	2,742	(265)
Net increase (decrease) in cash, cash equivalents and restricted cash	(3,473)	3,294	(6,539)
Cash, cash equivalents and restricted cash, beginning of period	3,838	544	7,083
Cash, cash equivalents and restricted cash, end of period	$ 365	$ 3,838	$ 544

CONSOLIDATED STATEMENTS OF CHAN

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Millions	Total	Additional Paid-In Capital	AOCI	Accumulated Deficit	Total Controlling Interests	Noncontrolling Interest	Preferred Stock	Common Stock
Beginning of period at Dec. 31, 2014	$ 3,023	$ 3,338	$ 20	$ (736)	$ 3,023	$ 0	$ 400	$ 1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	47			50	50	(3)
Equity issuance for acquisition, net (Note 15)	99	99			99
Other comprehensive income, net of tax	0		(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 15)	(250)	(250)			(250)
End of period at Dec. 31, 2015	2,919	3,187	19	(686)	2,921	(2)	400	1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	(1,244)			(1,240)	(1,240)	(4)
TEUs (Note 12)	359	359			359
Other comprehensive income, net of tax	4		2		2	2
Share-based compensation expense, net of tax	22	22			22
Dividends paid	(22)	(22)			(22)
Other	1	1		(1)		1
End of period at Dec. 31, 2016	2,039	3,547	21	(1,927)	2,042	(3)	400	1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	72			76	76	(4)
Equity issuance for acquisition, net (Note 15)	150	150			150
Preferred stock conversion	0	400					(400)
Other comprehensive income, net of tax	11		11		11
Share-based compensation expense, net of tax	19	19			19
Acquisition of non-controlling interest	(375)	(375)			(375)
Dividends paid	(22)	(22)			(22)
Other	(1)					(1)
End of period at Dec. 31, 2017	$ 1,893	$ 3,719	$ 32	$ (1,851)	$ 1,901	$ (8)	$ 0	$ 1

Organization and Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Organization and Operations	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. We report the results of our power generation business as five segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area, and changed our organizational structure to manage our assets, make financial decisions, and allocate resources based upon the market areas in which our plants operate. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. All significant intercompany transactions have been eliminated. Please read Note 21—Segment Information for further discussion. On February 2, 2017, Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. On February 7, 2017, (“the ENGIE Acquisition Closing Date”), Dynegy acquired approximately 9,017 MW of generation, 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 “ENGIE Acquisition”). Please read Note 3—Acquisitions and Divestitures for further discussion. On October 29, 2017, Dynegy and Vistra Energy Corp., a Delaware corporation (“Vistra Energy”), entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the Merger Agreement, which has been approved by the boards of directors of both companies, Dynegy will merge with and into Vistra Energy in a tax-free, all-stock transaction, with Vistra Energy continuing as the surviving corporation (the “Merger”). Under the terms of the agreement, Dynegy stockholders will receive 0.652 shares of Vistra Energy common stock for each share of Dynegy common stock they own, resulting in Vistra Energy stockholders and Dynegy stockholders owning approximately 79 percent and 21 percent, respectively, of the combined company. During 2017, we incurred approximately $17 million in costs related to the Merger, which are included in General and administrative expense in our consolidated statement of operations. We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions, including, among others, (a) approval by Vistra Energy’s stockholders of the issuance of the Vistra Energy common stock in the Merger, scheduled for March 2, 2018, and (b) receipt of all requisite regulatory approvals including FERC, the Public Utility Commission of Texas and the New York Public Service Commission. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions. The Merger Agreement contains customary representations, warranties and covenants of Dynegy and Vistra Energy, and contains certain termination rights for both Dynegy and Vistra Energy. If the Merger Agreement is terminated because Dynegy’s Board of Directors changes its recommendation to stockholders or Dynegy enters into a definitive agreement for a superior proposal, Dynegy will be required to pay Vistra Energy a termination fee of $87 million . If the Merger Agreement is terminated for a failure to obtain certain requisite regulatory approvals or Vistra Energy’s Board of Directors changes its recommendation in favor of the Merger, Vistra Energy may be required to pay Dynegy a termination fee of $100 million .

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies	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 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 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 long-lived assets, (v) estimating the scope, costs and timing of remediation work related to Asset Retirement Obligations (“AROs”), (vi) assessing future tax exposure and the realization of deferred tax assets, (vii) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (viii) 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, 2017 , the Company had no restricted cash balances, and as of December 31, 2016 , the Company had the following restricted cash balances: (amounts in millions) Restricted cash, current: Cash deposits associated with certain letters of credit (1) $ 41 Pre-funded original issue discount on the Term Loan (2) 20 Interest earned on funds in escrow 1 $ 62 Restricted cash, long-term: Restricted cash related to the issuance of the Term Loan (2) $ 2,000 _________________________________________ (1) Upon the emergence of Genco from bankruptcy, approximately $35 million of these deposits were returned to Dynegy. (2) Upon the close of the ENGIE Acquisition, as defined herein, the proceeds from the issuance of the Term Loan were released from escrow. Please read Note 13—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 1 to 40 Office and other equipment 1 to 28 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. We recorded impairments on certain of our assets in 2017. Please read Note 8—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 the identifiable tangible and intangible net assets acquired. The carrying amount of our goodwill is periodically reviewed, at least annually, for impairment and when certain indicators of impairment exist on an interim basis. We have elected October 1 for our annual assessment. 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 to determine whether it is more likely than not (a likelihood of more than 50 percent ) that an impairment has occurred or we can directly perform a quantitative assessment of our reporting units. In the absence of sufficient qualitative factors, we will compare 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, an impairment charge is recognized for the excess. There were no impairments of goodwill for the year ended December 31, 2017. We wrote off approximately $27 million of goodwill during the year ended December 31, 2017 related to divestitures of facilities located within our reporting units. Please see Note 3—Acquisitions and Divestitures for further information. 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. Please see Use of Estimates above for a description of the significant estimates used by management in determining our liability. 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) 2017 2016 Balance at beginning of year $ 287 $ 280 Accretion expense 20 20 Liabilities settled (8 ) (1 ) Revision of previous estimate (1) 22 (12 ) Acquisitions 24 — Divestitures (16 ) — Balance at end of year $ 329 $ 287 __________________________________________ (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. 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. The outstanding shares of our Preferred Stock converted to approximately 12.9 million shares of Common Stock on November 1, 2017 (the “Mandatory Conversion Date”). Our preferred shares were mandatorily convertible, were not redeemable and are classified within stockholders’ equity. We presented the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares were 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. On October 2, 2017, our Board of Directors declared a dividend on our mandatory convertible preferred stock of $1.34 per share, or approximately $5 million in the aggregate. Please see Note 15—Stockholders’ Equity for further information. 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 interest rate contracts are generally classified as either inflows or outflows from operating activities on the consolidated statements of cash flows. However, due to an other-than-insignificant financing element at inception on a portion of our interest rate swaps, certain of our cash flows related to these contracts are classified as financing activities. Please read Note 13—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 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. 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. We also account for changes in the tax code when enacted. 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. Please read Note 14—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 financial statements to evaluate the nature and financial effects of the business combination. In addition, ASC 805 requires transaction costs to be expensed as incurred. Variable Interest Entities . We evaluate our interests in variable interest entities (“VIEs”) to determine if we are considered the primary beneficiary and should therefore consolidate the VIE. The primary beneficiary of a VIE is the party that both: (i) has the power to direct the activities of a VIE that most significantly impact its economic performance and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE. Accounting Standards Adopted Goodwill. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements. Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $(33) million , and $26 million of cash prepayments from operating activities to investing activities in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015 , respectively. In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explains the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, we reclassified a change of approximately $2 million and $26 million of restricted cash from operating activities and $2.021 billion and $5.148 billion of restricted cash from investing activities to Net increase (decrease) in cash, cash equivalents, and restricted cash in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015 , respectively. Additionally, restricted cash of $39 million and $2.062 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2016 and $5.213 billion and $39 million are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2015 . The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets that sum to the total of the same such amounts shown in our consolidated statements of cash flows: (amounts in millions) December 31, 2017 December 31, 2016 December 31, 2015 Cash and cash equivalents $ 365 $ 1,776 $ 505 Restricted cash included in current assets (1) — 62 39 Restricted cash included in long-term assets (2) — 2,000 — Total cash, cash equivalents and restricted cash $ 365 $ 3,838 $ 544 __________________________________________ (1) Year ended December 31, 2016, includes $41 million related to collateral and $21 million placed in escrow for the issuance of the Term Loan ( $20 million of pre-funded original issue discount and $1 million interest income earned). Year ended December 31, 2015, includes $39 million related to collateral. (2) Relates to amounts placed into escrow for the issuance of the Term Loan. 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. We adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements. Accounting Standards Not Yet Adopted Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements. Pensions. In March 2017, the FASB issued ASU 2017-07-Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the 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 based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. The guidance in this ASU is effective for fiscal years, and interim

Acquisitions and Divestitures

Acquisitions and Divestitures	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Acquisitions and Divestitures	Note 3—Acquisitions and Divestitures Acquisitions ENGIE Acquisition. On the ENGIE Acquisition Closing Date, pursuant to the terms of the stock purchase agreement, as amended and restated on June 27, 2016, (the “ENGIE Acquisition 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 “ENGIE Acquisition”). Business Combination Accounting The ENGIE Acquisition has been accounted for in accordance with ASC 805 with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the ENGIE Acquisition Closing Date. A summary of the various techniques used to fair value the identifiable assets and liabilities, as well as their classification within the fair value hierarchy are listed below. • Working capital was valued using available market information (Level 2). • Acquired PP&E, excluding those assets classified as held-for-sale, was valued using a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model (Level 3). The DCF model was created for each power generation facility based on its remaining useful life, and: ◦ for the years 2017 and 2018, included gross margin forecasts using quoted forward commodity market prices; ◦ for the years 2019 through 2026, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors; ◦ for periods beyond 2026, we assumed a 2.5 percent growth rate. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, as well as capital expenditures for the years 2017 through 2021, and for years thereafter assumed a 2.5 percent growth rate. These cash flows were discounted using discount rates of approximately 9 percent to 13 percent for gas-fired, and approximately 13 percent to 14 percent for coal-fired, generation facilities, based upon the plant’s age, efficiency, region, and years until retirement. • Acquired PP&E classified as held-for-sale was valued based upon the sale price of the assets (Level 3). • Acquired derivatives were valued using the methods described in Note 5—Fair Value Measurements (Level 2 or Level 3). • Contracts with terms that were not at current market prices were also valued using a DCF analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability. • AROs were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3). The accounting for the ENGIE Acquisition is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the first quarter of 2018. The significant assets and liabilities for which provisional amounts are recognized are PP&E, deferred income taxes, and taxes other than deferred income taxes. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuation is completed, not to exceed one year from the ENGIE Acquisition Closing Date, and any material adjustments identified that existed as of the acquisition date will be recognized in the period in which they are identified. The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017: (amounts in millions) Base purchase price $ 3,300 Working capital adjustments and other (31 ) Fair value of total consideration transferred $ 3,269 Cash $ 20 Accounts receivable 22 Inventory 95 Prepayments and other current assets 3 Assets from risk management activities (including current portion of $21 million) 25 Property, plant and equipment 2,775 Investment in unconsolidated affiliate 132 Intangible assets (including current portion of $7 million) 50 Assets held-for-sale 472 Other long-term assets 131 Total assets acquired 3,725 Accounts payable 18 Liabilities from risk management activities (including current portion of $13 million) 16 Asset retirement obligations 19 Intangible liabilities (including current portion of $16 million) 30 Deferred income taxes, net 372 Other long-term liabilities 1 Total liabilities assumed 456 Net assets acquired $ 3,269 EquiPower Acquisition. On April 1, 2015, we purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ECP thereby acquiring (i) five combined-cycle natural gas-fired facilities in Connecticut, Massachusetts, and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas- and oil-fired peaking facilities in Ohio, and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”). In a related transaction on the same date, we purchased, through a wholly owned subsidiary, 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of Energy Capital Partners (“ECP”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”). The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio, and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments. Duke Midwest Acquisition. On April 2, 2015, we purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation in (i) three combined-cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) one retail energy business for a base purchase price of $2.8 billion in cash (the “Duke Midwest Acquisition”), subject to certain adjustments. The following table summarizes acquisition costs incurred related to the ENGIE Acquisition, the EquiPower Acquisition and the Duke Midwest Acquisition, 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) 2017 2016 2015 Acquisition costs $ 38 $ 5 $ 86 Revenues $ 3,079 $ 2,280 $ 1,703 Operating income $ 86 $ 235 $ 230 Pro Forma Results. The unaudited pro forma financial results for the years ended December 31, 2017, 2016 and 2015 assume the February 2017 ENGIE Acquisition occurred on January 1, 2016 and the April 2015 EquiPower and Duke Midwest Acquisitions 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 the above dates, nor are they indicative of future results of operations. The unaudited pro forma financial results for the three years ended December 31, 2017 include adjustments of $38 million , $5 million , and $86 million , respectively, for non-recurring acquisition costs. Year Ended December 31, (amounts in millions) 2017 2016 2015 Revenues $ 4,899 $ 5,046 $ 4,860 Net income (loss) $ 77 $ (1,361 ) $ 308 Net loss attributable to noncontrolling interest $ (4 ) $ (4 ) $ (3 ) Net income (loss) attributable to Dynegy Inc. $ 81 $ (1,357 ) $ 311 Other. On April 12, 2017, we received approximately $25 million of cash related to the 2013 New Ameren Energy Resources, LLC (“AER”) Acquisition. As a result, we have recorded $25 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2017 . During the year ended December 31, 2016, we received proceeds of $14 million of cash related to the AER Acquisition. As a result, we recorded $14 million in Other income and expense, net in our consolidated statement of operations for the year ended December 31, 2016 .

Risk Management Activities, Der

Risk Management Activities, Derivatives, and Financial Instruments	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities, Derivatives and Financial Instruments	Note 4—Risk Management Activities, Derivatives and Financial Instruments The nature of our business 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,” 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, 2017 , 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) (62 ) MWh $ (150 ) Electricity basis derivatives (3) (25 ) MWh $ (4 ) Natural gas derivatives (2) 404 MMBtu $ (4 ) Natural gas basis derivatives 120 MMBtu $ (1 ) Physical heat rate derivatives (4) 177/(17) MMBtu/MWh $ (95 ) Heat rate option 6/(1) MMBtu/MWh $ (4 ) Emissions derivatives 8 Metric Ton $ 2 Interest rate swaps 1,961 U.S. Dollar $ 7 Common stock warrants (5) 9 Warrant $ (2 ) _________________________________________ (1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $47 million . (2) Mainly comprised of swaps and physical forwards. (3) Comprised of FTRs and swaps. (4) Comprised of swaps which settle on the relationship of power pricing to natural gas pricing. (5) 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, 2017 and 2016 . As of December 31, 2017 and 2016 , there were no gross amounts available to be offset that were not offset in our consolidated balance sheets. December 31, 2017 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 $ 155 $ (112 ) $ — $ 43 Interest rate contracts Assets from risk management activities 20 (5 ) — 15 Total derivative assets $ 175 $ (117 ) $ — $ 58 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (411 ) $ 112 $ 47 $ (252 ) Interest rate contracts Liabilities from risk management activities (13 ) 5 — (8 ) Common stock warrants Accrued liabilities and other current liabilities and other long-term liabilities (2 ) — — (2 ) Total derivative liabilities $ (426 ) $ 117 $ 47 $ (262 ) Total derivatives $ (251 ) $ — $ 47 $ (204 ) 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 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, 2017 , the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features, in a liability position and not fully collateralized, is $32 million for which we have posted no 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, 2017 and 2016 , 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, 2017 December 31, 2016 (amounts in millions) Gross collateral posted with counterparties $ 92 $ 116 Less: Collateral netted against risk management liabilities 47 54 Net collateral within Prepayments and other current assets $ 45 $ 62 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, 2017, 2016 and 2015 include the impact of derivative financial instruments as presented below. Derivatives Not Designated as Hedges Location of Gain (Loss) Recognized in Income on Derivatives Year Ended December 31, 2017 2016 2015 (amounts in millions) Commodity contracts Revenues $ (58 ) $ 270 $ 194 Interest rate contracts Interest expense $ 16 $ (5 ) $ (15 ) Common stock warrants Other income and (expense), net $ 16 $ 6 $ 54

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value Measurements	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, 2017 and 2016 , 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, 2017 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 71 $ 6 $ 77 Natural gas derivatives — 62 10 72 Physical heat rate derivatives — 4 — 4 Emissions derivatives — 2 — 2 Total assets from commodity risk management activities — 139 16 155 Assets from interest rate contracts — 20 — 20 Total assets $ — $ 159 $ 16 $ 175 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (200 ) $ (31 ) $ (231 ) Natural gas derivatives — (71 ) (6 ) (77 ) Physical heat rate derivatives — (99 ) — (99 ) Heat rate option — — (4 ) (4 ) Total liabilities from commodity risk management activities — (370 ) (41 ) (411 ) Liabilities from interest rate contracts — (13 ) — (13 ) Liabilities from outstanding common stock warrants (2 ) — — (2 ) Total liabilities $ (2 ) $ (383 ) $ (41 ) $ (426 ) 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 ) 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, heat rate derivative valuations are derived using a DCF model, which uses modeled forward natural gas and power prices, and the heat rate option is 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. 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, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, and natural gas 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, 2017 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) (14 ) Million MWh $ (23 ) Basis spread + liquid location Basis spread $4.25 - $6.25 FTRs (22 ) Million MWh $ (2 ) Historical congestion Forward price $0 - $6.00 Physical heat rate derivatives 4/0 Million MMBtu $ — Discounted Cash Flow Forward price $2.00 - $2.80 / $22 - $27 Heat rate option 6/1 Million MMBtu $ (4 ) Option models Power price volatility 30% - 50% / 70% - 100% Natural gas derivatives (1) 95 Million MMBtu $ 4 Illiquid location fixed price Forward price $2.00 - $2.45 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts. 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, 2017 (amounts in millions) Electricity Natural Gas Derivatives Heat Rate Option Total Balance at December 31, 2016 $ 8 $ (6 ) $ — $ 2 Total gains (losses) included in earnings (30 ) 5 — (25 ) Settlements (1) (4 ) 5 — 1 Option premiums received — — (4 ) (4 ) Acquired derivatives 1 — — 1 Balance at December 31, 2017 $ (25 ) $ 4 $ (4 ) $ (25 ) Unrealized gains (losses) relating to instruments held as of December 31, 2017 $ (30 ) $ 5 $ — $ (25 ) Year Ended December 31, 2016 (amounts in millions) Electricity 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 Acquired derivatives (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 __________________________________________ (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 material transfers between Level 1, Level 2 and Level 3 for the years ended December 31, 2017 and 2016 . 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. Impairments. During the years ended December 31, 2017, 2016 and 2015 , we recorded impairment charges related to certain of our facilities, materials and supplies inventory and assets held-for-sale using fair value measurements. See Note 3—Acquisitions and Divestitures , Note 7—Inventory and Note 8—Property, Plant and Equipment for further discussion. Certain impairments were determined through a DCF model using similar fair value methodologies used to value our business acquisitions. 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, 2017 and 2016 , respectively. December 31, 2017 December 31, 2016 (amounts in millions) Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: Term Loan, due 2024 (1) Level 2 $ (1,944 ) $ (2,021 ) $ (2,213 ) $ (2,250 ) Revolving Facility (1) Level 2 $ — $ — $ — $ — 6.75% Senior Notes, due 2019 (1) Level 2 $ (845 ) $ (873 ) $ (2,083 ) $ (2,137 ) 7.375% Senior Notes, due 2022 (1) Level 2 $ (1,734 ) $ (1,844 ) $ (1,731 ) $ (1,665 ) 5.875% Senior Notes, due 2023 (1) Level 2 $ (493 ) $ (508 ) $ (492 ) $ (431 ) 7.625% Senior Notes, due 2024 (1) Level 2 $ (1,237 ) $ (1,344 ) $ (1,237 ) $ (1,156 ) 8.034% Senior Notes, due 2024 (1) Level 2 $ (188 ) $ (198 ) $ — $ — 8.00% Senior Notes, due 2025 (1) Level 2 $ (739 ) $ (812 ) $ (738 ) $ (703 ) 8.125% Senior Notes, due 2026 (1) Level 2 $ (842 ) $ (933 ) $ — $ — 7.00% Amortizing Notes, due 2019 (TEUs) (1) Level 2 $ (51 ) $ (54 ) $ (78 ) $ (90 ) Forward capacity agreement (1) Level 3 $ (215 ) $ (215 ) $ (205 ) $ (205 ) Inventory financing agreements Level 3 $ (48 ) $ (48 ) $ (129 ) $ (127 ) Equipment financing agreements (1) Level 3 $ (97 ) $ (97 ) $ (73 ) $ (73 ) Genco: Liabilities subject to compromise (2) Level 3 $ — $ — $ (825 ) $ (366 ) __________________________________________ (1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion. (2) Carrying amounts represent the Genco senior notes that were 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 20—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, 2017 and 2016 , our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $7 million and $79 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, 2017 and 2016 , we had $45 million and $62 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, 2017 and 2016 , we were not holding any collateral received from counterparties.

Cash Flow Information

Cash Flow Information	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Cash Flow Information	Note 6—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) 2017 2016 2015 Interest paid (net of amount capitalized of $2, $10, and $12, respectively) $ 555 $ 548 $ 491 Taxes paid (net of refunds) $ (5 ) $ (1 ) $ 2 Other non-cash investing and financing activity: Change in capital expenditures included in accounts payable $ 7 $ (13 ) $ (8 ) Change in capital expenditures pursuant to equipment financing agreements $ 24 $ 11 $ 63 Issuance of 2017 Warrants $ 17 $ — $ — Issuance of senior notes related to the Genco restructuring $ 188 $ — $ — Sale of interest in Conesville facility $ (58 ) $ — $ — Acquisition of interest in Zimmer facility $ 27 $ — $ — Non-cash consideration transferred for acquisitions $ — $ — $ 105

Inventory

Inventory	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Inventory	Note 7—Inventory A summary of our inventories is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Materials and supplies $ 242 $ 182 Coal 166 238 Fuel oil 15 17 Natural gas 9 — Emissions allowances (1) 13 8 Total $ 445 $ 445 __________________________________________ (1) At December 31, 2017 and December 31, 2016 , a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt —Emissions Repurchase Agreements for further discussion. As discussed in Note 9—Joint Ownership of Generating Facilities , Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. We determined that we would not be able to recover the carrying value of our inventory at these facilities and, as a result, recognized a charge of $14 million in Impairments in our consolidated statements of operations for the year ended December 31, 2017 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 8—Property, Plant and Equipment A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Power generation $ 9,998 $ 7,537 Buildings and improvements 955 944 Office and other equipment 115 98 Property, plant and equipment 11,068 8,579 Accumulated depreciation (2,184 ) (1,458 ) Property, plant and equipment, net $ 8,884 $ 7,121 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) 2017 2016 2015 Total interest costs incurred $ 576 $ 556 $ 487 Capitalized interest $ 2 $ 10 $ 12 Impairments During the years ended December 31, 2017, 2016 and 2015 , we recognized the following impairments in our consolidated statements of operations (amounts in millions). Facility Fair Value 2017 2016 2015 Baldwin (1) $ 97 $ — $ 645 $ — Stuart (2) $ — — 56 — Newton FGD (3) $ — — 148 — Killen (4) $ — 20 — — Hennepin (1) $ 16 10 — — Havana (1) $ 37 89 — — Wood River (5) $ — — — 74 Brayton Point (6) $ 86 — — 25 Total PP&E Impairments $ 119 $ 849 $ 99 Inventory $ — 14 — — Equity investment $ 173 — 9 — Assets held-for-sale, including $9 of allocated goodwill $ 176 15 — — Total Impairments $ 148 $ 858 $ 99 _________________________________________ (1) Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. As part of our impairment analysis, we changed the remaining useful lives of certain of our facilities. (2) We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model. (3) We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The impairment charge was equal to the capitalized cost of the project. (4) In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. As a result, the DCF model for the facility indicated negative cash flows, resulting in an impairment charge equal to its book value. (5) Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs. The impairment was measured using a DCF model. (6) Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility retired in May 2017. The impairment was measured using a DCF model. Brayton Point Retirement The Brayton Point facility officially retired on June 1, 2017. During the year ended December 31, 2017 , we recognized approximately $12 million of severance costs, which were classified within Operating and maintenance expense in our consolidated statement of operations.

Joint Ownership of Generating F

Joint Ownership of Generating Facilities	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Joint Ownership of Generating Facilities	Note 9—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 is included within the corresponding financial statement line items in our consolidated statements of operations. During 2017, in an effort to simplify structure and drive operating efficiencies, we acquired or exchanged ownership interests in certain of our jointly owned generating facilities. As a result, we now own 100 percent of Miami Fort and Zimmer and disposed of our full interest in Conesville. No ownership changes occurred related to the Stuart and Killen facilities, as they are scheduled to be retired mid-2018. The following tables present the ownership interests of the jointly owned facilities as of December 31, 2017 and 2016 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2017 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Stuart (1)(2) 39.0 % $ 1 $ — $ — $ 1 Killen (1)(2) 33.0 % $ — $ — $ — $ — 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 __________________________________________ (1) Facilities not operated by Dynegy. (2) Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy then owned 71.9 percent of the Zimmer facility and no longer had an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the twelve months ended December 31, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer. On December 8, 2017, Dynegy finalized the purchase of AES Ohio Generation, LLC’s and The Dayton Power and Light Company’s (collectively, “AES”) 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $70 million in cash for PP&E, Inventory, and the assumption of certain liabilities, subject to customary adjustments. Dynegy now owns 100 percent of Zimmer and Miami Fort, which are fully consolidated as of December 31, 2017. The transactions above were accounted for as business combinations using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures . Note 10—Unconsolidated Investments Equity Method Investments NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2017 , our equity method investment in NELP included in our consolidated balance sheets was $123 million . Upon the acquisition, we recognized basis differences in the net assets of approximately $39 million primarily related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. For the year ended December 31, 2017 , we recorded $8 million in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2017 , we received distributions of $17 million , of which $12 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows. Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As a result, we recorded an impairment charge of $9 million to Impairments in our consolidated statements of operations for the year ended December 31, 2016 , to write down our investment in Elwood to the sales price. 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, 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 to be 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 on investment. Both used the accumulated earnings approach and were reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows.

Unconsolidated Investments

Unconsolidated Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Unconsolidated Investments	Note 9—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 is included within the corresponding financial statement line items in our consolidated statements of operations. During 2017, in an effort to simplify structure and drive operating efficiencies, we acquired or exchanged ownership interests in certain of our jointly owned generating facilities. As a result, we now own 100 percent of Miami Fort and Zimmer and disposed of our full interest in Conesville. No ownership changes occurred related to the Stuart and Killen facilities, as they are scheduled to be retired mid-2018. The following tables present the ownership interests of the jointly owned facilities as of December 31, 2017 and 2016 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2017 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Stuart (1)(2) 39.0 % $ 1 $ — $ — $ 1 Killen (1)(2) 33.0 % $ — $ — $ — $ — 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 __________________________________________ (1) Facilities not operated by Dynegy. (2) Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy then owned 71.9 percent of the Zimmer facility and no longer had an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the twelve months ended December 31, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer. On December 8, 2017, Dynegy finalized the purchase of AES Ohio Generation, LLC’s and The Dayton Power and Light Company’s (collectively, “AES”) 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $70 million in cash for PP&E, Inventory, and the assumption of certain liabilities, subject to customary adjustments. Dynegy now owns 100 percent of Zimmer and Miami Fort, which are fully consolidated as of December 31, 2017. The transactions above were accounted for as business combinations using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures . Note 10—Unconsolidated Investments Equity Method Investments NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At December 31, 2017 , our equity method investment in NELP included in our consolidated balance sheets was $123 million . Upon the acquisition, we recognized basis differences in the net assets of approximately $39 million primarily related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. For the year ended December 31, 2017 , we recorded $8 million in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our consolidated statements of operations. For the year ended December 31, 2017 , we received distributions of $17 million , of which $12 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows. Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As a result, we recorded an impairment charge of $9 million to Impairments in our consolidated statements of operations for the year ended December 31, 2016 , to write down our investment in Elwood to the sales price. 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, 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 to be 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 on investment. Both used the accumulated earnings approach and were reflected as Distributions from unconsolidated investments in our consolidated statements of cash flows.

Intangible Assets and Liabiliti

Intangible Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Intangible Assets and Liabilities	Note 11—Intangible Assets and Liabilities The following table summarizes the components of our intangible assets and liabilities as of December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 178 $ (131 ) $ 47 $ 260 $ (206 ) $ 54 Gas transport contracts 30 (13 ) 17 13 (6 ) 7 Total intangible assets $ 208 $ (144 ) $ 64 $ 273 $ (212 ) $ 61 Intangible Liabilities: Electricity contracts $ (11 ) $ 7 $ (4 ) $ (28 ) $ 26 $ (2 ) Coal contracts — — — (49 ) 42 (7 ) Coal transport contracts (48 ) 44 (4 ) (86 ) 73 (13 ) Gas transport contracts (58 ) 19 (39 ) (41 ) 8 (33 ) Gas storage contracts (2 ) 1 (1 ) — — — Total intangible liabilities $ (119 ) $ 71 $ (48 ) $ (204 ) $ 149 $ (55 ) Intangible assets and liabilities, net $ 89 $ (73 ) $ 16 $ 69 $ (63 ) $ 6 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2017, 2016 and 2015 : Year Ended December 31, (amounts in millions) 2017 2016 2015 Electricity contracts, net (1) $ 32 $ 70 $ 75 Coal contracts, net (2) (5 ) (41 ) (60 ) Coal transport contracts, net (2) (9 ) (27 ) (32 ) Gas transport contracts, net (2) (5 ) 19 6 Gas storage contracts, net (2) (1 ) — — Total $ 12 $ 21 $ (11 ) __________________________________________ (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, 2017 is as follows: 2018 — $11 million , 2019 — $17 million , 2020 — $2 million , 2021 — ($3) million , and 2022 — ($4) million . The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017: (amounts in millions) Gross Carrying Amount Weighted-Average Amortization Period (months) Intangible Assets: Electricity contracts $ 34 39 Gas transport contracts 16 47 Total intangible assets $ 50 41 Intangible Liabilities: Electricity contracts $ (11 ) 32 Gas contracts — 1 Gas transport contracts (17 ) 35 Gas storage contracts (2 ) 13 Total intangible liabilities $ (30 ) 33 Total intangible assets and liabilities, net $ 20

Tangible Equity Units

Tangible Equity Units	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Tangible Equity Units	Note 12—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 which was 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 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”. In 2016, 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, at a conversion price ranging from 5.0201 shares to 6.1996 shares. 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.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Note 13—Debt A summary of our long-term debt is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Secured Obligations: Term Loan, due 2024 $ 2,018 $ 2,224 Revolving Facility — — Forward Capacity Agreement 241 219 Inventory Financing Agreements 48 129 Subtotal secured obligations 2,307 2,572 Unsecured Obligations: 7.00% Amortizing Notes, due 2019 (TEUs) 53 80 6.75% Senior Notes, due 2019 850 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 8.034% Senior Notes, due 2024 188 — 8.00% Senior Notes, due 2025 750 750 8.125% Senior Notes, due 2026 850 — Equipment Financing Agreements 132 97 Subtotal unsecured obligations 6,323 6,527 Total debt obligations 8,630 9,099 Unamortized debt discounts and issuance costs (197 ) (120 ) 8,433 8,979 Less: Current maturities, including unamortized debt discounts and issuance costs, net 105 201 Total long-term debt $ 8,328 $ 8,778 Certain of our debt instruments contain change of control provisions, which will not be triggered with the Merger with Vistra Energy. For further discussion of the Merger, see Note 1—Organization and Operations . Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2017 are as follows: (in millions) 2018 $ 115 2019 971 2020 136 2021 59 2022 1,760 Thereafter 5,589 Total $ 8,630 Credit Agreement As of December 31, 2017 , we had a $3.563 billion credit agreement, as amended, that consisted of (i) a $2.018 billion seven -year senior secured term loan facility (the “Term Loan”) and (ii) $1.545 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Term Loan, the “Credit Agreement”). During the year ended December 31, 2017 , we made the following changes to the Credit Agreement: • During 2017, we amended the Credit Agreement to increase the revolver capacity by $120 million and to extend the maturity date on $450 million in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date. • On the ENGIE Acquisition Closing Date, we amended the Credit Agreement to (i) reduce the interest rate applicable to the Term Loan by 75 basis points and (ii) exchange our previous Term Loan for the current Term Loan. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximatel y $7 million in our consolidated statements of operations in the first quarter of 2017, of which approximately $5 million was r elated to the write-off of unamortized deferred financing costs and approximately $2 million was related to the write-off of unamortized debt discount. • On August 22, 2017, we repaid $200 million of our Term Loan. As a result of this transaction, we recorded a loss on early extinguishment of debt of approximately $8 million in our consolidated statements of operations for the year ended December 31, 2017 , of which $6 million was related to the write-off of unamortized deferred financing costs and $2 million was related to the write-off of unamortized debt discount. • On December 20, 2017, we amended the Credit Agreement to reduce interest rate margins applicable to the Term Loan from 2.25 percent to 1.75 percent with respect to base rate borrowings and from 3.25 percent to 2.75 percent with respect to LIBOR borrowings through an exchange. Additional reductions from 2.25 percent to 1.50 percent with respect to base rate borrowings and from 2.75 percent to 2.50 percent with respect to LIBOR borrowings are available to the Company based on certain corporate ratings or corporate family ratings from Moody’s and S&P. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $6 million in our consolidated statements of operations in the fourth quarter of 2017, of which approximately $4 million was related to the write-off of unamortized deferred financing costs, approximately $1 million was related to the write-off of unamortized debt discount, and approximately $1 million related to fees. At December 31, 2017 , there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $353 million , which reduce the amount available under the Revolving Facility. In the first quarter of 2017 there was $300 million drawn on the Revolving Facility, and subsequently fully repaid in the fourth quarter of 2017. 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. Under the Credit Agreement, if Dynegy utilizes 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio of 4.00 :1.00. Based on the calculation outlined in the Credit Agreement, we were in compliance with these covenants as of December 31, 2017 . Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Consolidated Senior Secured Net Debt, as defined in the Credit Agreement. Interest Rate Swaps. In March 2017, we amended our existing interest rate swaps to more closely match the terms of our Term Loan. The swaps have an aggregate notional value of approximately $761 million at an average fixed rate of 3.03 percent and expire between the second quarter of 2018 and the second quarter of 2020. In a previous extension to the existing interest rate swaps, 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. Additionally, in May 2017, we entered into new interest rate swap agreements. The swaps have an aggregate notional value of approximately $1.2 billion at an average fixed rate of 1.97 percent and expire in the first quarter of 2024. Any cash flows related to the settlement of these swaps are reflected as an operating activity in our consolidated statements of cash flows. Senior Notes The senior notes are unsecured and unsubordinated obligations of the Company and are guaranteed by each of the Company’s current and future wholly-owned domestic subsidiaries that from time to time are a borrower or guarantor under the Credit Agreement. The senior notes indentures limit, among other things, the ability of the Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30 percent of total assets. As a result of Genco’s emergence from bankruptcy, we issued $188 million of new seven -year unsecured notes as partial consideration in exchange for Genco’s existing senior notes. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. On August 21, 2017, we issued $850 million of 8.125 percent senior notes due 2026 (the “2026 Senior Notes”) in a private placement transaction. Interest is payable semiannually in arrears on January 30 and July 30 of each year, beginning January 30, 2018. Dynegy used the proceeds of the offering, together with proceeds from the sale of certain facilities, and cash-on-hand to repurchase $1.25 billion of its 6.75 percent senior notes due 2019 and repay $200 million of its Term Loan, as noted above. In connection with the extinguishment of a portion of our 2019 senior notes, we recorded a loss on early extinguishment of debt of approximately $58 million in our consolidated statements of operations for the year ended December 31, 2017 , of which approximately $44 million related to a premium paid in excess of debt principal, approximately $8 million related to the write-off of unamortized deferred financing costs, and approximately $6 million related to fees. The Company, pursuant to a Registration Rights Agreement, has agreed to use commercially reasonable efforts to register the 2026 Senior Notes by August 16, 2018. Otherwise, the 2026 Senior Notes are generally identical in all material respects to Dynegy’s other outstanding senior notes. 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 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 12—Tangible Equity Units for further discussion. Letter of Credit Facilities Dynegy has a Letter of Credit Reimbursement Agreement with an issuing bank, for an LC in an amount not to exceed $55 million . In July 2017, the expiry date of the facility was extended one year, to September 19, 2018. At December 31, 2017 , there was $55 million of LCs outstanding under this facility. Following the ENGIE Acquisition Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide LCs in an amount not to exceed $50 million . At December 31, 2017 , there was $30 million of LCs outstanding under this facility. The facility matured February 7, 2018 and the LCs under this facility have since been transferred to under the Dynegy revolver. Forward Capacity Agreement As of December 31, 2017, we have sold a portion of our PJM capacity that cleared for Planning Years 2018-2019, 2019-2 020 and 2020-2021 to a financial institution. Dynegy will continue to be subject to the performance obligations as well as any associated performance pe nalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance of $241 million with an implied interest rate of 4.9 percent . On March 29, 2017, we replaced an existing Planning Year 2017-2018 contract in the amount of $110 million , with a Planning Year 2019-2020 contract in the amount of $121 million . On July 7, 2017, we replaced $99 million of $109 million of an existing Planning Year 2018-2019 contract with a Planning Year 2020-2021 contract in the amount of $110 million . 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. On May 31, 2017, the Brayton Point inventory financing agreement terminated and the remaining obligation was paid. The Brayton Point facility officially retired on June 1, 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. In February 2017, we repurchased approximately $30 million of the previously sold RGGI inventory. We are obligated to repurchase the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent . As of December 31, 2017 , there was $48 million , in aggregate, outstanding under these agreements. In February 2018, we repaid all amounts outstanding under these agreements. Equipment Financing Agreements Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2019 to 2026. 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 $97 million . The $35 million discount is currently being amortized as interest expense over the life of the payments.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 14—Income Taxes We are subject to U.S. federal and state income taxes on our operations. Tax Reform Act. On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act (“TCJA”). Substantially all of the provisions of the TCJA are effective for taxable years beginning after December 31, 2017. The TCJA includes significant changes to the Internal Revenue Code of 1986, as amended (“the Code”), including amendments which significantly change the taxation of business entities. The more significant changes in the TCJA that impact Dynegy are: • reductions in the corporate federal income tax rate from 35 percent to 21 percent , • repeal of the corporate Alternative Minimum Tax (“AMT”) providing for refunds of excess AMT credits, • limiting the utilization of Net Operating Losses (“NOLs”) arising after December 31, 2017 to 80 percent of taxable income with an indefinite carryforward (existing NOLs can continue to be utilized at 100 percent of taxable income with a 20-year carryforward), and • limiting the deduction of net business interest expense to 30 percent of adjusted taxable income as defined in the TCJA. As a result of the reduction in the U.S. federal corporate tax rate, Dynegy has recorded a $394 million reduction to our net deferred tax assets, including the federal benefit of state deferred taxes, which was fully offset by a decrease in our valuation allowance for the year ended December 31, 2017. Additionally, we have recorded a $223 million current tax benefit and long term tax receivable in 2017 related to the expected refund of our existing AMT credits. In accordance with Staff Accounting Bulletin 118, the amounts recorded in the fourth quarter of 2017 related to the TCJA represent reasonable estimates based on our analysis to date and are considered to be provisional and subject to revision during 2018. Provisional amounts were recorded for the re-measurement of our 2017 U.S. deferred taxes and ancillary state tax effects. These amounts are considered to be provisional as we continue to assess available tax methods and elections and refine our computations. Additionally, further regulatory guidance related to the TCJA is expected to be issued in 2018 which may result in changes to our current estimates. Our losses from continuing operations before income taxes were $538 million , $1.289 billion and $427 million for the years ended December 31, 2017, 2016 and 2015 , respectively, which were solely from domestic sources. Our components of income tax benefit related to losses from continuing operations were as follows: Year Ended December 31, (amounts in millions) 2017 2016 2015 Current tax benefit (expense) $ 233 $ 15 $ (3 ) Deferred tax benefit 377 30 477 Income tax benefit $ 610 $ 45 $ 474 Our income tax benefit related to losses from continuing operations before income taxes for each of the years ended December 31, 2017, 2016 and 2015 were equivalent to effective rates of 113 percent , 3 percent , and 111 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) 2017 2016 2015 Expected tax benefit at U.S. statutory rate (35%) $ 189 $ 451 $ 149 State taxes 35 16 68 Permanent differences (1) (21 ) (4 ) 16 Non-deductible goodwill (10 ) — — Valuation allowance (2)(3) 879 (404 ) 271 NOL adjustments from use limitations (13 ) (17 ) — Adjustment to AMT credits (17 ) — (26 ) Change in federal tax rate as included in TCJA (429 ) — — Other (3 ) 3 (4 ) Income tax benefit $ 610 $ 45 $ 474 __________________________________________ (1) Permanent items for years ended December 31, 2017, 2016 and 2015 included a benefit of less than $1 million , a benefit of $2 million , and a benefit of $18 million , 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 years ended December 31, 2017 and 2016 includes $8 million and $5 million , respectively, of income tax expense for non-deductible fees related to the Genco Plan. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. Income tax benefit for the year ended December 31, 2017 , includes $22 million for non-deductible legal fees related to the ENGIE Acquisition. (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) The ENGIE Acquisition on February 7, 2017 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $354 million reduction to our valuation allowance in 2017. We also recorded a benefit for the repeal of the corporate AMT in the amount of $223 million as included in the TCJA. Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows: Year Ended December 31, (amounts in millions) 2017 2016 Non-current deferred tax assets: NOL carryforwards $ 1,195 $ 1,629 AMT, state, and other tax credit carryforwards 25 241 Reserves (legal, environmental and other) 4 7 Pension and other post-employment benefits 11 18 Asset retirement obligations 68 85 Deferred financing costs and intangible/other contracts 22 48 Derivative contracts 69 57 Other 29 46 Subtotal 1,423 2,131 Less: valuation allowance (852 ) (1,704 ) Total non-current deferred tax assets $ 571 $ 427 Non-current deferred tax liabilities: Depreciation and other property differences $ (560 ) $ (371 ) Derivative contracts (7 ) (44 ) Other (11 ) (17 ) Total non-current deferred tax liabilities $ (578 ) $ (432 ) Net non-current deferred tax liabilities $ (7 ) $ (5 ) NOL Carryforwards. As of December 31, 2017 , we had approximately $4.6 billion of NOLs and $3.6 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2037. 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. For the years ended December 31, 2017 and 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 $18 million and $16 million , respectively. Dynegy has recorded a $223 million tax benefit in 2017 related to the expected refund of its existing AMT Credits as provided for in the TCJA. 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, 2017 and 2016 , we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 2017 and 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. The changes in the valuation allowance were as follows: Year Ended December 31, 2017 2016 2015 Beginning of period $ 1,704 $ 1,276 $ 1,535 Changes in valuation allowance—continuing operations: Charged to costs and expenses (854 ) 428 (259 ) Charged to other accounts 2 — — End of period $ 852 $ 1,704 $ 1,276 Unrecognized Tax Benefits. We are complete with federal income tax audits by the Internal Revenue Service (“IRS”) through 2015 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 2013 or earlier with few exceptions. A reconciliation of our beginning and ending amounts of unrecognized tax benefits were as follows: Year Ended December 31, amounts in millions 2017 2016 2015 Unrecognized tax benefits, beginning of period $ 3 $ 3 $ 4 Increase due to ENGIE acquisition 63 — — Decrease due to rate changes (26 ) — — Decrease due to settlements and payments — — (1 ) Unrecognized tax benefits, end of period $ 40 $ 3 $ 3 As of December 31, 2017 , approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Stockholders' Equity	Note 15—Stockholders’ Equity 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. Our 4 million shares of Series A Mandatory Convertible Preferred Stock converted on November 1, 2017, into approximately 12.9 million shares of our common stock, whereupon we reclassified the balance of Preferred Stock to Additional paid-in-capital. Stock Purchase Agreement-Terawatt On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the investment funds of ECP, pursuant to which, at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 shares of Dynegy common stock for $150 million (the “PIPE Transaction”). ECP Buyout Dynegy settled its payment obligation to ECP of $375 million on the ENGIE Acquisition Closing Date. This payment is recorded as a reduction in additional paid-in capital in our consolidated balance sheet and is reflected as a purchase of a noncontrolling interest in financing activities in our consolidated statement of cash flows as of December 31, 2017 . 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 12—Tangible Equity Units for further discussion. 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, 2017, 2016 and 2015 : Shares outstanding balance as of December 31, (in millions) 2017 2016 2015 Shares outstanding at the beginning of the period 117 117 124 Shares issued under the PIPE Transaction 14 — — Shares issued as consideration for the EquiPower Acquisition — — 3 Shares repurchases (in treasury) — — (11 ) Shares issued from conversion of preferred stock 13 — — Shares issued under long-term compensation plans — — 1 Shares outstanding at the end of period 144 117 117 Warrants. As of the Plan Effective Date, we issued to then-existing 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 expired on October 2, 2017 . During 2017, we issued 9.0 million warrants (the “2017 Warrants”), each of which entitles the holder to purchase one share of Dynegy common stock, to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. The 2017 Warrants have an exercise price of $35 per share of common stock and a seven -year term expiring on February 2, 2024. The warrants are recorded as Other long-term liabilities in our consolidated balance sheet 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 20—Genco Chapter 11 Bankruptcy and 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 “ 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 LTIP. The 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 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 LTIP will expire no later than 10 years from the date of the grant. All RSUs granted under the 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 2.5 million and 1.5 million shares of RSU’s granted in 2017 and 2016, respectively, 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. We paid $3 million in cash for 0.4 million of the RSU’s accounted for as liabilities that vested during the year ended December 31, 2017 . All PSUs granted under the 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. We estimate forfeiture rates based on our actual forfeitures. Compensation expense related to options, RSUs and PSUs granted totaled $44 million , $31 million and $28 million for the years ended December 31, 2017, 2016 and 2015 , 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 $15 million , $11 million and $10 million for the years ended December 31, 2017, 2016 and 2015 , respectively. As of December 31, 2017 , $31 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 1.43 years. The total fair value of options, RSUs and PSUs vested was $26 million , $27 million and $18 million for the years ended December 31, 2017, 2016 and 2015 , respectively. We did not capitalize any share-based compensation in the years ended December 31, 2017, 2016 and 2015 . We settled 0.1 million RSUs related to severances and retirements for $1 million in cash for the year ended December 31, 2017 . We did not settle any share-based compensation for cash in the years ended December 31, 2016 and 2015. No options were exercised for the years ended December 31, 2017 and 2016. Cash received from option exercises was $0.5 million and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the year ended December 31, 2015. The following summarizes our stock option activity: Year Ended December 31, 2017 Options (in thousands) Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in years) Aggregate Intrinsic Value Outstanding at beginning of period 2,805 $ 18.69 Granted 1,454 $ 8.02 Forfeited (10 ) $ 27.24 Expired (42 ) $ 21.79 Outstanding at end of period 4,207 $ 14.95 7.65 $ 6.4 Vested and unvested expected to vest 4,207 $ 14.95 7.65 $ 6.4 Exercisable at end of period 2,023 $ 20.02 6.40 $ 0.5 During the years ended December 31, 2017, 2016 and 2015 , 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, 2016 and 2015 was $11.05 and $27.43 , respectively. The intrinsic value of options exercised during the years ended December 31, 2016 and 2015 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, 2017 2016 2015 Dividend Yield $ — $ — $ — Expected volatility (1) 48.50 % 41.19 % 27.70 % Risk-free interest rate (2) 2.07 % 1.42 % 1.64 % Expected option life (3) 5.5 years 5.5 years 5.5 years Weighted average grant-date fair value $ 3.71 $ 4.37 $ 7.93 __________________________________________ (1) For the years ended December 31, 2017, 2016 and 2015 , 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, including both those settled in shares and those settled in cash: Year Ended December 31, 2017 RSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 2,717 $ 16.11 Granted 3,177 $ 7.99 Vested and released (1,241 ) $ 19.04 Forfeited (107 ) $ 11.08 Outstanding at end of period 4,546 $ 9.75 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, 2016 and 2015 was $11.20 and $28.93 , 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, 2017 PSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 1,221 $ 16.48 Granted 583 $ 8.02 Vested and released (3 ) $ 26.66 Forfeited (186 ) $ 23.10 Outstanding at end of period 1,615 $ 12.65 The weighted average grant date fair value of PSUs granted during the years ended December 31, 2016 and 2015 was $16.48 and $27.54 . 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 and subsequent to 2016, the fair value is determined using TSR for one-half of the award and the other half using pre-determined adjusted 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. 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 12—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, 2017, 2016 and 2015 : Year Ended December 31, (in millions, except per share amounts) 2017 2016 2015 Shares outstanding at the beginning of the period 140 117 124 Weighted-average shares during the period of: Shares issuances 13 — 4 Shares converted from preferred stock 2 — — Shares repurchases — — (3 ) Prepaid stock purchase contract (TEUs) (1) — 12 — Basic weighted-average shares 155 129 125 Dilution from potentially dilutive shares (2) 7 — 1 Diluted weighted-average shares (3) 162 129 126 _________________________________________ (1) The minimum settlement amount, or 23.1 million 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 12—Tangible Equity Units for further discussion. (2) Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of: • 5.4 million additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount ( 28.5 million shares); and • 1.9 million additional shares attributable to restricted stock units and performance stock units. (3) 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 year ended December 31, 2016. For the years ended December 31, 2017, 2016 and 2015 , 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) 2017 2016 2015 Stock options 2.8 2.8 0.5 Restricted stock units — 1.3 — Performance stock units — 1.2 — Warrants (1) 9.0 15.6 15.6 Series A 5.375% mandatory convertible preferred stock (2) — 12.9 12.9 TEUs — 5.4 — Total 11.8 39.2 29.0 _________________________________________ (1) During 2017, we issued 9.0 million warrants to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. Warrants to purchase 15.6 million shares of our Common Stock expired on October 2, 2017. (2) On November 1, 2017, our outstanding Preferred Stock was converted to approximately 12.9 million shares of Common Stock. 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) 2017 2016 2015 Beginning of period $ 21 $ 19 $ 20 Other comprehensive income before reclassifications: Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively) 19 2 3 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) (8 ) (5 ) (4 ) Net current period other comprehensive income (loss), net of tax 11 2 (1 ) End of period $ 32 $ 21 $ 19 __________________________________________ (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 17—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 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 16—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. On March 30, 2017, the court denied Plaintiffs’ motion to certify a class action, which will be subject to an interlocutory appeal granted by the Ninth Circuit on June 13, 2017. At this time we cannot reasonably estimate a potential loss. Advatech Dispute. On September 2, 2016, our Genco subsidiary 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 and believes the proper amount is less than $1 million . On October 27, 2016, Advatech initiated the dispute resolution process under the Contract and filed for arbitration on March 16, 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. We believe the risk of a material loss related to this dispute to be remote. We dispute the allegations and will defend our position vigorously. Vistra Merger Stockholder Litigation. On January 4, 2018, a putative class action complaint was filed in the United States District Court for the Southern District of Texas against Dynegy, Dynegy’s individual Board members, and Vistra Energy alleging that the December 13, 2017 S-4 Registration Statement related to the Merger “omits material information with respect to the Merger, which renders the Registration Statement false and misleading.” Two additional lawsuits have been filed in Texas and Delaware making nearly identical allegations but excluding Vistra as a defendant. We dispute the allegations and will defend our position vigorously. Wood River Rail Dispute. On November 30, 2017, Dynegy Midwest Generation, LLC (“DMG”) received notification that BNSF Railway Company and Norfolk Southern Railway Company were initiating dispute resolution related to DMG’s suspension of its Wood River Rail Transportation Agreement with the railroads. The parties are attempting to negotiate a resolution per the mandatory terms of the dispute resolution provision of the agreement. If the parties are unable negotiate a resolution, the railroads can initiate an arbitration to resolve the dispute. At this time, we view the likelihood of material loss as remote and dispute the railroads’ allegations and, if arbitration ensues, will defend our position vigorously. 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. Dynegy is participating in the investigation. We believe the risk of a material loss related to the investigation to be remote. 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. Zimmer NOVs. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. We are unable to predict the outcome of these matters. Killen and Stuart NOVs. The EPA issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. In May and June 2017, we received two letters from the Sierra Club providing notice of its intent to sue various Dynegy entities and the owner and operator of the Killen and Stuart facilities, respectively, alleging violations of opacity standards under the CAA. The Dayton Power and Light Company, the operator of Killen and Stuart, is expected to act on behalf of itself and the co-owners with respect to these matters. We are unable to predict the outcome of these matters. 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 MISO segment’s Edwards facility. In 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 scheduled the remedy phase trial for March 2019. 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. Coal Combustion Residuals/ Groundwater. MISO Segment . In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities’ Coal Combustion Residuals (“CCR”) surface impoundments. 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 those closure plans. At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and closure options and riverbank stabilizing options. By letter dated January 31, 2018, Prairie Rivers Network provided 60-day notice of its intent to sue our subsidiary Dynegy Midwest Generation, LLC under the federal Clean Water Act for alleged unauthorized discharges from the surface impoundments at our Vermilion facility and alleged related violations of the facility’s NPDES permit. We dispute the allegations and will vigorously defend our position. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the CCR rule. If remediation measures concerning groundwater are necessary at any of our coal-fired MISO Segment facilities, 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. CCR surface impoundment and landfill closure costs are 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, 2017 . Coal Purchase Commitments. At December 31, 2017 , we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $802 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, 2017 , we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $837 million . Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In prior periods, we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers. As of December 31, 2017 , our obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $707 million in the event all contracts are terminated by us. In addition, we have committed to securing capital spares and turbine uprates for our gas-fueled generation fleet to help minimize production disturbances, improve efficiency, and increase generation. As of December 31, 2017 , we have obligations to purchase spare parts and turbine uprates of $112 million with payments made through 2026, of which $103 million reflects spare parts received and upgrades completed. 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, 2017 , we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $212 million . Gas Transportation. At December 31, 2017 , 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 $183 million . Operating Leases. Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases per year for the years 2018-2022 are as follows: (in millions) 2018 $ 6 2019 $ 5 2020 $ 5 2021 $ 5 2022 $ 4 During the years ended December 31, 2017, 2016 and 2015 , we recognized rental expense of approximately $5 million , $5 million and $5 million , respectively. Other Obligations. We have other obligations of $25 million for contracts in place to purchase limestone and ash, $17 million for interconnection services, $23 million for water services and $23 million for other miscellaneous items which are individually insignificant. 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. We have accrued no amounts with respect to the indemnifications as of December 31, 2017 because none were probable of occurring, nor could they be reasonably estimated.

Employee Compensation, Savings,

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Employee Compensation, Savings, Pension Other Post-Employment Benefit Plans	Note 17—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, 2017, 2016 and 2015 , our contributions related to these plans were approximately $63 million , $43 million and $50 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. Dynegy Inc. 401(k) Savings Plans. For the years ended December 31, 2017, 2016 and 2015 , 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: • 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, 2017 . During the years ended December 31, 2017, 2016 and 2015 , we recognized aggregate costs related to our 401(k) Plans of $13 million , $15 million and $10 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 December 2017, we merged our Dynegy Inc. Retirement Plan into the Sithe Stable Pension Account Plan, which is sponsored by our wholly-owned subsidiary, Sithe Energies, Inc. The combined plan was re-named as the Dynegy Pension Plan, and the sponsorship of the combined plan was transferred from Sithe Energies, Inc. to Dynegy Inc. In 2017, the Dynegy pension and other post-employment plans were amended as a result of negotiations with former Duke Midwest union participants, IBEW Local 1347. As part of these amendments, the participants’ previous pension plan accrued benefits were frozen as of December 31, 2017 and began accruing on January 1, 2018 with a minimum interest crediting rate of 4 percent . Other post-employment plans were amended to provide retiree medical plan benefits to only certain participants as of January 1, 2018. As a result of these amendments, we remeasured our affected plans and recorded a net-of-tax gain of approximately $15 million through accumulated other comprehensive income during 2017. 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 affected plans and recorded a net-of-tax gain of approximately $17 million through accumulated other comprehensive income. Additionally, 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) 2017 2016 2017 2016 Benefit obligation, beginning of the year $ 508 $ 483 $ 42 $ 74 Service cost 17 16 — 1 Interest cost 20 20 2 3 Actuarial loss 28 23 1 4 Benefits paid (36 ) (32 ) (4 ) (6 ) Plan change (10 ) (2 ) (1 ) (17 ) Settlements — — — (17 ) Acquisitions — — — — Divestitures — — — — Benefit obligation, end of the year $ 527 $ 508 $ 40 $ 42 Fair value of plan assets, beginning of the year $ 415 $ 410 $ 49 $ 67 Actual return on plan assets 65 37 4 2 Employer contributions 4 — — — Benefits paid (36 ) (32 ) (2 ) (3 ) Settlements — — — (17 ) Acquisitions — — — — Divestitures — — — — Transfers Out (1) — — (19 ) — Fair value of plan assets, end of the year $ 448 $ 415 $ 32 $ 49 Funded status $ (79 ) $ (93 ) $ (8 ) $ 7 __________________________________________ (1) As permitted by EEI’s other post-employment plan for EEI union employees, part of the overfunded portion of the plan assets was segregated in 2017 to offset the employer cost of the active EEI employees’ health and welfare benefits. Our accumulated benefit obligation related to pension plans was $527 million and $501 million as of December 31, 2017 and 2016 , respectively. Our accumulated benefit obligation related to other post-employment plans was $40 million and $42 million as of December 31, 2017 and 2016 , respectively. Amounts recognized in the consolidated balance sheets consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2017 2016 Non-current assets $ — $ 7 $ 33 $ 32 Current liabilities — — (2 ) (2 ) Non-current liabilities (79 ) (100 ) (20 ) (23 ) Net amount recognized $ (79 ) $ (93 ) $ 11 $ 7 Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2017 2016 Prior service credit $ (19 ) $ (12 ) $ (43 ) $ (47 ) Actuarial loss (gain) (8 ) 2 1 1 Net gain recognized $ (27 ) $ (10 ) $ (42 ) $ (46 ) 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, 2017, 2016 and 2015 for the defined benefit pension plans were $2 million , $1 million and $1 million , respectively. The net prior service credit that was amortized from AOCI into net periodic benefit cost during the years ended December 31, 2017, 2016 and 2015 for other post-employment benefit plans was $5 million , $4 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 2018 are as follows: (amounts in millions) Pension Benefits Other Benefits Prior service credit $ (3 ) $ (5 ) Actuarial gain — (1 ) $ (3 ) $ (6 ) 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) 2017 2016 2015 Service cost benefits earned during period $ 17 $ 16 $ 14 Interest cost on projected benefit obligation 20 20 18 Expected return on plan assets (25 ) (22 ) (23 ) Amortization of: Prior service credit (2 ) (1 ) (1 ) Actuarial gain — — — Net periodic benefit cost $ 10 $ 13 $ 8 Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2015 Service cost benefits earned during period $ — $ 1 $ 1 Interest cost on projected benefit obligation 2 3 4 Expected return on plan assets (2 ) (4 ) (4 ) Amortization of: Prior service credit (5 ) (4 ) (3 ) Actuarial gain (1 ) — — Net periodic benefit gain (6 ) (4 ) (2 ) Settlement cost (1) — 6 — Total benefit cost (gain) $ (6 ) $ 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, 2017 2016 2017 2016 Discount rate (1) 3.60 % 4.05 % 3.55 % 4.00 % 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, 2017 2016 2015 2017 2016 2015 Discount rate 3.60 % 4.05 % 4.35 % 3.55 % 4.00 % 4.35 % Dynegy - Expected return on plan assets 6.20 % 5.60 % 5.70 % N/A N/A N/A EEI - Expected return on plan assets (1) 6.40 % 5.90 % 6.00 % 5.75 % 5.40 % 5.50 % 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 5.75 percent , 5.40 percent , and 5.50 percent for the years ended December 31, 2017, 2016 and 2015 , respectively. The expected return on EEI’s other post-employment plan assets was 6.90 percent , 6.30 percent , and 6.20 percent for EEI union employees for the years ended December 31, 2017, 2016 and 2015 , respectively. The expected return on EEI’s other post-employment plan assets was 4.60 percent , 4.50 percent , and 4.80 percent for EEI salaried employees for the years ended December 31, 2017, 2016 and 2015 , respectively. (2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2017, 2016 and 2015 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 5.60 percent and 6.40 percent , respectively, for the year ended December 31, 2018. Our expected long-term rate of return on EEI’s other post-employment plan assets is 7.10 percent for EEI union employees and 4.50 percent for EEI salaried employees for the year ended December 31, 2018. 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 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, 2017 2016 2015 Health care cost trend rate assumed for next year 7.00 % 7.25 % 7.00 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2025 2025 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 $ — $ — 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, 2017 was approximately 46 percent to equity investments and approximately 54 percent to fixed income investments. Dynegy plan assets are routinely monitored and rebalanced as circumstances warrant. The EEI plans have not adopted a glide-path approach. The target asset mix for EEI’s plan assets as of December 31, 2017 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, 2017 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 7 $ — $ — $ 7 Equity securities: U.S. companies (1) 14 136 — 150 Non-U.S. companies (2) 1 19 — 20 International (3) 9 62 — 71 Fixed income securities (4) 63 169 — 232 Total $ 94 $ 386 $ — $ 480 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 Total $ 101 $ 365 $ — $ 466 ________________________________________ (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. Contributions and Payments. Our required benefit contributions for our pension and other post-employment benefit plans are as follows: (amounts in millions) Pension Benefits Other Benefits 2016 $ — $ 2 2017 $ 4 $ 2 2018 $ 13 $ 2 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 2018 $ 39 $ 3 2019 $ 38 $ 3 2020 $ 38 $ 3 2021 $ 38 $ 3 2022 $ 38 $ 2 2023 - 2027 $ 190 $ 11

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Note 18—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 2017 Revenues $ 1,247 $ 1,164 $ 1,437 $ 994 Operating income (loss) (1) $ (49 ) $ (182 ) $ 58 $ (239 ) Net income (loss) (2)(3)(4) $ 596 $ (296 ) $ (133 ) $ (95 ) Net income (loss) attributable to Dynegy Inc. common stockholders (2)(3)(4) $ 592 $ (302 ) $ (137 ) $ (95 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (2)(3)(4) $ 4.00 $ (1.96 ) $ (0.89 ) $ (0.58 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (2)(3)(4) $ 3.57 $ (1.96 ) $ (0.89 ) $ (0.58 ) 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 ) _____________________ (1) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include impairment charges of $20 million , $99 million , and $29 million , respectively. 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 8—Property, Plant and Equipment for more information. (2) The results for the quarters ended June 30, 2017, September 30, 2017, and December 31, 2017 include losses on sale of assets of $29 million , $78 million , and $15 million , respectively. See Note 3—Acquisitions and Divestitures and Note 9—Joint Ownership of Generating Facilities for more information. (3) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include income (loss) from bankruptcy reorganization items of $483 million , ($1) million , and $12 million , respectively. The results for the quarter ended December 31, 2016 include loss from Bankruptcy reorganization items of $96 million . See Note 20—Genco Chapter 11 Bankruptcy for more information. (4) The results for the quarters ended March 31, 2017 and December 31, 2017 include a $317 million and $37 million income tax benefit, respectively, from the partial release of our valuation allowance as a result of the ENGIE Acquisition. The results for the quarter ended December 31, 2017 include a $223 million tax benefit related to the expected refund of its existing AMT Credits as provided for in the TCJA. See Note 14—Income Taxes for more information.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Note 19—Condensed Consolidating Financial Information Dynegy’s senior notes are guaranteed by certain, but not all, of our wholly owned subsidiaries. The following condensed consolidating financial statements as of and for the years ended December 31, 2017, 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 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes. Please read Note 13—Debt for further discussion. 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 (excluding Electric Energy, Inc.) became a guarantor to the senior notes. Accordingly, condensed consolidating financial information previously reported has been retroactively adjusted to reflect the status of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries as of December 31, 2017 . 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, 2017 and December 31, 2016 . Condensed Consolidating Balance Sheet for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 233 $ 124 $ 8 $ — $ 365 Accounts receivable, net 126 4,269 14 (3,896 ) 513 Inventory — 415 30 — 445 Other current assets 8 288 2 (97 ) 201 Total Current Assets 367 5,096 54 (3,993 ) 1,524 Property, plant and equipment, net — 8,585 299 — 8,884 Investment in affiliates 16,132 — — (16,132 ) — Investment in unconsolidated affiliates — 123 — — 123 Goodwill — 772 — — 772 Other long-term assets 244 185 39 — 468 Intercompany note receivable 46 — — (46 ) — Total Assets $ 16,789 $ 14,761 $ 392 $ (20,171 ) $ 11,771 Current Liabilities Accounts payable $ 3,555 $ 471 $ 232 $ (3,891 ) $ 367 Other current liabilities 156 520 108 (102 ) 682 Total Current Liabilities 3,711 991 340 (3,993 ) 1,049 Debt, long-term portion, net 8,045 256 27 — 8,328 Intercompany note payable 3,042 46 — (3,088 ) — Other long-term liabilities 90 367 44 — 501 Total Liabilities 14,888 1,660 411 (7,081 ) 9,878 Stockholders’ Equity Dynegy Stockholders’ Equity 1,901 16,151 (19 ) (16,132 ) 1,901 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 1,901 13,109 (19 ) (13,090 ) 1,901 Noncontrolling interest — (8 ) — — (8 ) Total Equity 1,901 13,101 (19 ) (13,090 ) 1,893 Total Liabilities and Equity $ 16,789 $ 14,761 $ 392 $ (20,171 ) $ 11,771 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 $ 221 $ 26 $ — $ 1,776 Restricted cash 21 41 — — 62 Accounts receivable, net 141 2,604 39 (2,398 ) 386 Inventory — 326 119 — 445 Other current assets 12 408 2 (104 ) 318 Total Current Assets 1,703 3,600 186 (2,502 ) 2,987 Property, plant and equipment, net — 6,772 349 — 7,121 Investment in affiliates 12,175 — — (12,175 ) — Restricted cash 2,000 — — — 2,000 Other long-term assets 2 109 35 — 146 Goodwill — 799 — — 799 Intercompany note receivable — 8 — (8 ) — Total Assets $ 15,880 $ 11,288 $ 570 $ (14,685 ) $ 13,053 Current Liabilities Accounts payable $ 1,990 $ 443 $ 297 $ (2,398 ) $ 332 Other current liabilities 143 377 168 (104 ) 584 Total Current Liabilities 2,133 820 465 (2,502 ) 916 Liabilities subject to compromise — 832 — — 832 Debt, long-term portion, net 8,531 216 31 — 8,778 Intercompany note payable 3,042 — — (3,042 ) — Other long-term liabilities 132 313 51 (8 ) 488 Total Liabilities 13,838 2,181 547 (5,552 ) 11,014 Stockholders’ Equity Dynegy Stockholders’ Equity 2,042 12,152 23 (12,175 ) 2,042 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,042 9,110 23 (9,133 ) 2,042 Noncontrolling interest — (3 ) — — (3 ) Total Equity 2,042 9,107 23 (9,133 ) 2,039 Total Liabilities and Equity $ 15,880 $ 11,288 $ 570 $ (14,685 ) $ 13,053 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 4,557 $ 422 $ (137 ) $ 4,842 Cost of sales, excluding depreciation expense — (2,790 ) (279 ) 137 (2,932 ) Gross margin — 1,767 143 — 1,910 Operating and maintenance expense — (881 ) (114 ) — (995 ) Depreciation expense — (757 ) (54 ) — (811 ) Impairments — (148 ) — — (148 ) Gain (loss) on sale of assets, net — (123 ) 1 — (122 ) General and administrative expense (28 ) (155 ) (6 ) — (189 ) Acquisition and integration costs (54 ) (3 ) — — (57 ) Operating loss (82 ) (300 ) (30 ) — (412 ) Bankruptcy reorganization items (18 ) 512 — — 494 Earnings from unconsolidated investments — 8 — — 8 Equity in losses from investments in affiliates 824 — — (824 ) — Interest expense (597 ) (20 ) (13 ) 14 (616 ) Loss on early extinguishment of debt (79 ) — — — (79 ) Other income and expense, net 28 53 — (14 ) 67 Income (loss) before income taxes 76 253 (43 ) (824 ) (538 ) Income tax benefit (Note 14) — 610 — — 610 Net income (loss) 76 863 (43 ) (824 ) 72 Less: Net loss attributable to noncontrolling interest — (4 ) — — (4 ) Net income (loss) attributable to Dynegy Inc. $ 76 $ 867 $ (43 ) $ (824 ) $ 76 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 3,942 $ 468 $ (92 ) $ 4,318 Cost of sales, excluding depreciation expense — (2,112 ) (261 ) 92 (2,281 ) Gross margin — 1,830 207 — 2,037 Operating and maintenance expense — (796 ) (144 ) — (940 ) Depreciation expense — (612 ) (77 ) — (689 ) Impairments — (858 ) — — (858 ) Gain (loss) on sale of assets, net (2 ) 1 — — (1 ) General and administrative expense (7 ) (148 ) (6 ) — (161 ) Acquisition and integration costs (10 ) (1 ) — — (11 ) Other — (9 ) (8 ) — (17 ) Operating loss (19 ) (593 ) (28 ) — (640 ) Bankruptcy reorganization items — (96 ) — — (96 ) Earnings from unconsolidated investments — 7 — — 7 Equity in losses from investments in affiliates (715 ) — — 715 — Interest expense (538 ) (83 ) (9 ) 5 (625 ) Other income and expense, net 32 38 — (5 ) 65 Loss before income taxes (1,240 ) (727 ) (37 ) 715 (1,289 ) Income tax benefit (Note 14) — 45 — — 45 Net loss (1,240 ) (682 ) (37 ) 715 (1,244 ) Less: Net loss attributable to noncontrolling interest — (4 ) — — (4 ) Net loss attributable to Dynegy Inc. $ (1,240 ) $ (678 ) $ (37 ) $ 715 $ (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 $ — $ 3,508 $ 525 $ (163 ) $ 3,870 Cost of sales, excluding depreciation expense — (1,874 ) (317 ) 163 (2,028 ) Gross margin — 1,634 208 — 1,842 Operating and maintenance expense — (717 ) (122 ) — (839 ) Depreciation expense — (505 ) (82 ) — (587 ) Impairments — (74 ) (25 ) — (99 ) Loss on sale of assets, net — (1 ) — — (1 ) General and administrative expense (6 ) (116 ) (6 ) — (128 ) Acquisition and integration costs — (124 ) — — (124 ) Operating income (loss) (6 ) 97 (27 ) — 64 Earnings from unconsolidated investments — 1 — — 1 Equity in earnings from investments in affiliates 476 — — (476 ) — Interest expense (475 ) (69 ) (4 ) 2 (546 ) Other income and expense, net 55 1 — (2 ) 54 Income (loss) before income taxes 50 30 (31 ) (476 ) (427 ) Income tax benefit (Note 14) — 472 2 — 474 Net income (loss) 50 502 (29 ) (476 ) 47 Less: Net income attributable to noncontrolling interest — (3 ) — — (3 ) Net income (loss) attributable to Dynegy Inc. $ 50 $ 505 $ (29 ) $ (476 ) $ 50 Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 76 $ 863 $ (43 ) $ (824 ) $ 72 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of $5 22 (3 ) — — 19 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (7 ) — (1 ) — (8 ) Other comprehensive loss from investment in affiliates (4 ) — — 4 — Other comprehensive income (loss), net of tax 11 (3 ) (1 ) 4 11 Comprehensive income (loss) 87 860 (44 ) (820 ) 83 Less: Comprehensive loss attributable to noncontrolling interest — (4 ) — — (4 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 87 $ 864 $ (44 ) $ (820 ) $ 87 Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (1,240 ) $ (682 ) $ (37 ) $ 715 $ (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 ) (681 ) (26 ) 703 (1,240 ) Less: Comprehensive income (loss) attributable to noncontrolling interest 2 (2 ) — (2 ) (2 ) Total comprehensive loss attributable to Dynegy Inc. $ (1,238 ) $ (679 ) $ (26 ) $ 705 $ (1,238 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 50 $ 502 $ (29 ) $ (476 ) $ 47 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of zero (8 ) 7 5 — 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 — 7 4 (11 ) — Comprehensive income (loss) 50 509 (25 ) (487 ) 47 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 (2 ) — (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 49 $ 511 $ (25 ) $ (486 ) $ 49 Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (427 ) $ 899 $ 113 $ — $ 585 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (208 ) (16 ) — (224 ) Acquisitions, net of cash acquired/divestitures (3,244 ) (75 ) — — (3,319 ) Distributions from unconsolidated affiliate — 12 — — 12 Proceeds from sales of assets, net 775 (4 ) 1 — 772 Net intercompany transfers 691 — — (691 ) — Net cash used in investing activities (1,778 ) (275 ) (15 ) (691 ) (2,759 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 1,743 — — — 1,743 Repayments of borrowings (2,487 ) (46 ) (56 ) — (2,589 ) Proceeds from issuance of equity, net of issuance costs 150 — — — 150 Payments of debt extinguishment costs (50 ) — — — (50 ) Preferred stock dividends paid (22 ) — — — (22 ) Interest rate swap settlement payments (20 ) — — — (20 ) Acquisition of noncontrolling interest (375 ) — — — (375 ) Payments related to bankruptcy settlement (128 ) (5 ) — — (133 ) Net intercompany transfers — (631 ) (60 ) 691 — Intercompany borrowings, net of repayments 80 (80 ) — — — Other financing (3 ) — — — (3 ) Net cash provided by (used in) financing activities (1,112 ) (762 ) (116 ) 691 (1,299 ) Net decrease in cash and cash equivalents (3,317 ) (138 ) (18 ) — (3,473 ) Cash, cash equivalents and restricted cash, beginning of period 3,550 262 26 — 3,838 Cash, cash equivalents and restricted cash, end of period $ 233 $ 124 $ 8 $ — $ 365 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 $ (476 ) $ 1,090 $ 31 $ — $ 645 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (243 ) (50 ) — (293 ) Proceeds from sales of assets, net 171 5 — — 176 Distributions from unconsolidated affiliate — 14 — — 14 Net intercompany transfers 958 — — (958 ) — Other investing — 10 — — 10 Net cash provided by (used in) investing activities 1,129 (214 ) (50 ) (958 ) (93 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 2,816 198 — — 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 — (991 ) 33 958 — Other financing (3 ) — — — (3 ) Net cash provided by (used in) financing activities 2,570 (808 ) 22 958 2,742 Net increase in cash and cash equivalents 3,223 68 3 — 3,294 Cash, cash equivalents and restricted cash, beginning of period 327 194 23 — 544 Cash, cash equivalents and restricted cash, end of period $ 3,550 $ 262 $ 26 $ — $ 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 ) $ 682 $ (156 ) $ — $ 94 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (290 ) (11 ) — (301 ) Acquisitions, net of cash acquired/divestitures (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 ) (250 ) 89 (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 — (347 ) (103 ) 450 — Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (339 ) (292 ) (84 ) 450 (265 ) Net increase (decrease) in cash and cash equivalents (6,528 ) 140 (151 ) — (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 $ 194 $ 23 $ — $ 544

Genco Chapter 11 Bankruptcy

Genco Chapter 11 Bankruptcy	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Genco Chapter 11 Bankruptcy	Note 20—Genco Chapter 11 Bankruptcy On October 14, 2016, we entered into a restructuring support agreement with Genco and an ad hoc group of Genco bondholders to restructure the Genco senior notes. As a result of filing a prepackaged plan of reorganization (the “Genco Plan”), we reclassified the Genco senior notes as Liabilities subject to compromise in our consolidated balance sheet as of December 31, 2016. The amounts represented the allowed claims to be resolved in connection with our Chapter 11 proceedings. A summary of our liabilities subject to compromise as of December 31, 2016 is as follows: (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 Costs associated with the reorganization incurred prior to the Bankruptcy Petition of approximately $10 million have been recorded in General and administrative expense in our consolidated statement of operations for the year ended December 31, 2016. Costs post Genco’s Bankruptcy Petition of approximately $96 million have been recorded to Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2016, and primarily include the write-off of the remaining unamortized discount related to the Genco senior notes and legal expenses incurred. On December 9, 2016, 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 Genco Plan and Genco emerged from bankruptcy on February 2, 2017. As a result, we eliminated $825 million of Genco senior notes and $7 million of accrued interest in exchange for approximately $122 million of cash, $188 million of new seven -year unsecured notes, and 2017 Warrants to purchase up to 9 million shares of common stock with a fair value of $17 million . The 2017 Warrants, which have an exercise price of $35 per share of common stock, have a seven -year term expiring on February 2, 2024 and are recorded as Other long-term liabilities in our consolidated balance sheet as of December 31, 2017 . The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2017 : (amounts in millions) Liabilities subject to compromise, which were terminated $ 832 Less: Seven-year unsecured notes 188 Cash consideration 122 2017 Warrants, at fair value 17 Legal and consulting fees 11 Bankruptcy reorganization items $ 494 For income tax purposes, the income from cancellation of debt is excluded from taxable income in the current year and will instead reduce Genco’s tax attributes. During 2016, upon Genco’s petition for bankruptcy under Chapter 11, we analyzed Genco as a VIE. Based on the analysis, it was determined that Dynegy was the primary beneficiary of Genco and continued to receive the benefits and controlled the significant activities of Genco. As a result, Genco was consolidated by Dynegy as a VIE as of December 31, 2016.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 21—Segment Information We report the results of our operations in the following five segments based upon the market areas in which our plants operate: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO and (v) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). In the fourth quarter of 2017, we combined our previous MISO and IPH segments into a single MISO segment to better align our IPH assets, which reside within the MISO market area. Accordingly, the Company has recast data from prior periods to conform to the current year segment presentation. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. NY/NE also includes our Dynegy Energy Services retail business in Massachusetts. MISO also includes our Homefield Energy retail business in Illinois. Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2017, 2016 and 2015 is presented below: Segment Data as of and for the Year Ended December 31, 2017 (amounts in millions) PJM NY/NE ERCOT MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 2,352 $ 1,031 $ 276 $ 1,061 $ 122 $ — $ 4,842 Intercompany and affiliate revenues (90 ) (2 ) 1 91 — — — Total revenues $ 2,262 $ 1,029 $ 277 $ 1,152 $ 122 $ — $ 4,842 Depreciation expense $ (379 ) $ (224 ) $ (73 ) $ (75 ) $ (53 ) $ (7 ) $ (811 ) Impairments (49 ) — — (99 ) — — (148 ) Gain (loss) on sale of assets, net (36 ) (90 ) — 1 3 — (122 ) General and administrative expense — — — — — (189 ) (189 ) Acquisition and integration costs — — — — — (57 ) (57 ) Operating income (loss) $ 192 $ (113 ) $ (147 ) $ (44 ) $ (45 ) $ (255 ) $ (412 ) Bankruptcy reorganization items — — — 494 — — 494 Earnings from unconsolidated investments 3 5 — — — — 8 Interest expense — — — — — (616 ) (616 ) Loss on early extinguishment of debt — — — — — (79 ) (79 ) Other income and expense, net 16 — — 26 — 25 67 Loss before income taxes (538 ) Income tax benefit — — — — — 610 610 Net Income 72 Less: Net loss attributable to noncontrolling interest (4 ) Net Income attributable to Dynegy Inc. $ 76 Total assets—domestic $ 4,912 $ 3,374 $ 1,563 $ 812 $ 455 $ 655 $ 11,771 Investment in unconsolidated affiliate $ 67 $ 56 $ — $ — $ — $ — $ 123 Capital expenditures $ (103 ) $ (50 ) $ (26 ) $ (26 ) $ (12 ) $ (7 ) $ (224 ) Segment Data as of and for the Year Ended December 31, 2016 (amounts in millions) PJM NY/NE MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 2,147 $ 836 $ 1,165 $ 142 $ — $ 4,290 Intercompany revenues 55 1 (28 ) — — 28 Total revenues $ 2,202 $ 837 $ 1,137 $ 142 $ — $ 4,318 Depreciation expense $ (346 ) $ (215 ) $ (81 ) $ (42 ) $ (5 ) $ (689 ) Impairments (65 ) — (793 ) — — (858 ) Gain (loss) 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 ) $ (832 ) $ (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 benefit — — — — 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 $ 1,065 $ 485 $ 3,795 $ 13,053 Capital expenditures $ (160 ) $ (64 ) $ (52 ) $ (7 ) $ (10 ) $ (293 ) Segment Data as of and for the Year Ended December 31, 2015 (amounts in millions) PJM NY/NE MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,708 $ 705 $ 1,279 $ 178 $ — $ 3,870 Intercompany revenues 8 (10 ) 2 — — — Total revenues $ 1,716 $ 695 $ 1,281 $ 178 $ — $ 3,870 Depreciation expense $ (281 ) $ (186 ) $ (68 ) $ (48 ) $ (4 ) $ (587 ) Impairments — (25 ) (74 ) — — (99 ) Loss on sale of assets, net — — — (1 ) — (1 ) General and administrative expense — — — — (128 ) (128 ) Acquisition and integration costs — — — — (124 ) (124 ) Operating income (loss) $ 423 $ (56 ) $ (43 ) $ (8 ) $ (252 ) $ 64 Earnings from unconsolidated investments 1 — — — — 1 Interest expense — — — — (546 ) (546 ) Other income and expense, net (2 ) — 1 — 55 54 Loss from continuing operations 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 $ 1,995 $ 534 $ 486 $ 11,459 Investment in unconsolidated affiliate $ 190 $ — $ — $ — $ — $ 190 Capital expenditures $ (106 ) $ (52 ) $ (119 ) $ (11 ) $ (13 ) $ (301 ) 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, 2017, 2016 and 2015 are presented below: (amounts in millions) Revenues Customers 2017 2016 2015 Segment(s) PJM $ 1,313 $ 1,366 $ 1,088 PJM, MISO MISO $ 506 $ 688 $ 842 MISO ISO-NE $ 669 $ 437 N/A MISO, NY/NE Employee Concentrations As of December 31, 2017 , approximately 40 percent of our employees are covered by a collective bargaining agreement.

Summary of Significant Accoun30

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of Consolidation and Basis of Presentation	Principles of Consolidation . The accompanying consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries 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	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. 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	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 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 long-lived assets, (v) estimating the scope, costs and timing of remediation work related to Asset Retirement Obligations (“AROs”), (vi) assessing future tax exposure and the realization of deferred tax assets, (vii) determining amounts to accrue for contingencies, guarantees, and indemnifications, and (viii) 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. 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. 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, 2017 , the Company had no restricted cash balances, and as of December 31, 2016 , the Company had the following restricted cash balances:
Accounts Receivable and Allowance for Doubtful Accounts	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	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. 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 1 to 40 Office and other equipment 1 to 28 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. We recorded impairments on certain of our assets in 2017. Please read Note 8—Property, Plant and Equipment for further information.
Goodwill, Intangible Assets and Liabilities	Goodwill. Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of the identifiable tangible and intangible net assets acquired. The carrying amount of our goodwill is periodically reviewed, at least annually, for impairment and when certain indicators of impairment exist on an interim basis. We have elected October 1 for our annual assessment. 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 to determine whether it is more likely than not (a likelihood of more than 50 percent ) that an impairment has occurred or we can directly perform a quantitative assessment of our reporting units. In the absence of sufficient qualitative factors, we will compare 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, an impairment charge is recognized for the excess. There were no impairments of goodwill for the year ended December 31, 2017. We wrote off approximately $27 million of goodwill during the year ended December 31, 2017 related to divestitures of facilities located within our reporting units. Please see Note 3—Acquisitions and Divestitures for further information. 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	Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets when the liability is incurred. Please see Use of Estimates above for a description of the significant estimates used by management in determining our liability. 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.
Contingencies, Commitments, Guarantees and Indemnifications	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. 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	Preferred Stock. The outstanding shares of our Preferred Stock converted to approximately 12.9 million shares of Common Stock on November 1, 2017 (the “Mandatory Conversion Date”). Our preferred shares were mandatorily convertible, were not redeemable and are classified within stockholders’ equity. We presented the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares were 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. 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	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	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	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 interest rate contracts are generally classified as either inflows or outflows from operating activities on the consolidated statements of cash flows. However, due to an other-than-insignificant financing element at inception on a portion of our interest rate swaps, certain of our cash flows related to these contracts are classified as financing activities. Please read Note 13—Debt for more information.
Fair Value Measurements	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 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	Income Taxes. We file a consolidated U.S. federal income tax return. 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. We also account for changes in the tax code when enacted. 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. Please read Note 14—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.
Earnings (Loss) Per Share	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	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 financial statements to evaluate the nature and financial effects of the business combination. In addition, ASC 805 requires transaction costs to be expensed as incurred.
Variable Interest Entities	Variable Interest Entities . We evaluate our interests in variable interest entities (“VIEs”) to determine if we are considered the primary beneficiary and should therefore consolidate the VIE. The primary beneficiary of a VIE is the party that both: (i) has the power to direct the activities of a VIE that most significantly impact its economic performance and (ii) has an obligation to absorb losses or a right to receive benefits that could potentially be significant to the VIE.
Accounting Principles Adopted	Accounting Standards Adopted Goodwill. In January 2017, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“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 adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements. Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $(33) million , and $26 million of cash prepayments from operating activities to investing activities in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015 , respectively. In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explains the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We early adopted this ASU as of December 31, 2016 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, we reclassified a change of approximately $2 million and $26 million of restricted cash from operating activities and $2.021 billion and $5.148 billion of restricted cash from investing activities to Net increase (decrease) in cash, cash equivalents, and restricted cash in our consolidated statement of cash flows for the years ended December 31, 2016 and 2015 , respectively. Additionally, restricted cash of $39 million and $2.062 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2016 and $5.213 billion and $39 million are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our consolidated statement of cash flows for the year ended December 31, 2015 . The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets that sum to the total of the same such amounts shown in our consolidated statements of cash flows: (amounts in millions) December 31, 2017 December 31, 2016 December 31, 2015 Cash and cash equivalents $ 365 $ 1,776 $ 505 Restricted cash included in current assets (1) — 62 39 Restricted cash included in long-term assets (2) — 2,000 — Total cash, cash equivalents and restricted cash $ 365 $ 3,838 $ 544 __________________________________________ (1) Year ended December 31, 2016, includes $41 million related to collateral and $21 million placed in escrow for the issuance of the Term Loan ( $20 million of pre-funded original issue discount and $1 million interest income earned). Year ended December 31, 2015, includes $39 million related to collateral. (2) Relates to amounts placed into escrow for the issuance of the Term Loan. 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. We adopted this ASU on January 1, 2017 with no material impact on our consolidated financial statements. Accounting Standards Not Yet Adopted Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements. Pensions. In March 2017, the FASB issued ASU 2017-07-Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the 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 based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. 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 have established an implementation team to assess the impact the new accounting standard will have on our financial statements, as well as accounting policies, business processes and controls. Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements and industry specific guidance and develops a common revenue recognition standard whereby an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenues and cash flows from contracts with customers. The guidance in this ASU and its amendments are effective for interim and annual periods beginning after December 15, 2017, unless early adopted. We intend on adopting the ASU using the modified retrospective approach. We have finalized our evaluation of the impact that the new accounting standard will have on our financial statements. As a result of our evaluation, the Company did not identify any material changes to the timing of our revenue recognition. Changes to our disclosures will primarily include a regional presentation of our revenues disaggregated by revenue type - energy, capacity, and ancillary services, as well as disclosure of future performance obligations. We have assessed our accounting policies and internal processes and controls, and identified changes which will become effective upon adoption.

Summary of Significant Accoun31

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Schedule of Restricted Cash	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our consolidated balance sheets that sum to the total of the same such amounts shown in our consolidated statements of cash flows: (amounts in millions) December 31, 2017 December 31, 2016 December 31, 2015 Cash and cash equivalents $ 365 $ 1,776 $ 505 Restricted cash included in current assets (1) — 62 39 Restricted cash included in long-term assets (2) — 2,000 — Total cash, cash equivalents and restricted cash $ 365 $ 3,838 $ 544 __________________________________________ (1) Year ended December 31, 2016, includes $41 million related to collateral and $21 million placed in escrow for the issuance of the Term Loan ( $20 million of pre-funded original issue discount and $1 million interest income earned). Year ended December 31, 2015, includes $39 million related to collateral. (2) Relates to amounts placed into escrow for the issuance of the Term Loan. As of December 31, 2017 , the Company had no restricted cash balances, and as of December 31, 2016 , the Company had the following restricted cash balances: (amounts in millions) Restricted cash, current: Cash deposits associated with certain letters of credit (1) $ 41 Pre-funded original issue discount on the Term Loan (2) 20 Interest earned on funds in escrow 1 $ 62 Restricted cash, long-term: Restricted cash related to the issuance of the Term Loan (2) $ 2,000 _________________________________________ (1) Upon the emergence of Genco from bankruptcy, approximately $35 million of these deposits were returned to Dynegy. (2) Upon the close of the ENGIE Acquisition, as defined herein, the proceeds from the issuance of the Term Loan were released from escrow. Please read Note 13—Debt for further information.
Property, Plant and Equipment	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 1 to 40 Office and other equipment 1 to 28 A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Power generation $ 9,998 $ 7,537 Buildings and improvements 955 944 Office and other equipment 115 98 Property, plant and equipment 11,068 8,579 Accumulated depreciation (2,184 ) (1,458 ) Property, plant and equipment, net $ 8,884 $ 7,121
Schedule of Change in Asset Retirement Obligation	A summary of the changes related to our AROs is as follows: Year Ended December 31, (amounts in millions) 2017 2016 Balance at beginning of year $ 287 $ 280 Accretion expense 20 20 Liabilities settled (8 ) (1 ) Revision of previous estimate (1) 22 (12 ) Acquisitions 24 — Divestitures (16 ) — Balance at end of year $ 329 $ 287 __________________________________________ (1) Based on management’s review and assessment of CCR compliance timing and site-specific analysis.

Acquisitions and Divestitures (

Acquisitions and Divestitures (Tables)	12 Months Ended
	Dec. 31, 2017
Business Combinations [Abstract]
Schedule of Assets Acquired and Liabilities Assumed	The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017: (amounts in millions) Base purchase price $ 3,300 Working capital adjustments and other (31 ) Fair value of total consideration transferred $ 3,269 Cash $ 20 Accounts receivable 22 Inventory 95 Prepayments and other current assets 3 Assets from risk management activities (including current portion of $21 million) 25 Property, plant and equipment 2,775 Investment in unconsolidated affiliate 132 Intangible assets (including current portion of $7 million) 50 Assets held-for-sale 472 Other long-term assets 131 Total assets acquired 3,725 Accounts payable 18 Liabilities from risk management activities (including current portion of $13 million) 16 Asset retirement obligations 19 Intangible liabilities (including current portion of $16 million) 30 Deferred income taxes, net 372 Other long-term liabilities 1 Total liabilities assumed 456 Net assets acquired $ 3,269
Schedule of Acquisition and Related Costs	The following table summarizes acquisition costs incurred related to the ENGIE Acquisition, the EquiPower Acquisition and the Duke Midwest Acquisition, 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) 2017 2016 2015 Acquisition costs $ 38 $ 5 $ 86 Revenues $ 3,079 $ 2,280 $ 1,703 Operating income $ 86 $ 235 $ 230
Pro Forma Financial Results Related to Acquisition	Year Ended December 31, (amounts in millions) 2017 2016 2015 Revenues $ 4,899 $ 5,046 $ 4,860 Net income (loss) $ 77 $ (1,361 ) $ 308 Net loss attributable to noncontrolling interest $ (4 ) $ (4 ) $ (3 ) Net income (loss) attributable to Dynegy Inc. $ 81 $ (1,357 ) $ 311

Risk Management Activities, D33

Risk Management Activities, Derivatives and Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts and Interest Rate Swaps	As of December 31, 2017 , 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) (62 ) MWh $ (150 ) Electricity basis derivatives (3) (25 ) MWh $ (4 ) Natural gas derivatives (2) 404 MMBtu $ (4 ) Natural gas basis derivatives 120 MMBtu $ (1 ) Physical heat rate derivatives (4) 177/(17) MMBtu/MWh $ (95 ) Heat rate option 6/(1) MMBtu/MWh $ (4 ) Emissions derivatives 8 Metric Ton $ 2 Interest rate swaps 1,961 U.S. Dollar $ 7 Common stock warrants (5) 9 Warrant $ (2 ) _________________________________________ (1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $47 million . (2) Mainly comprised of swaps and physical forwards. (3) Comprised of FTRs and swaps. (4) Comprised of swaps which settle on the relationship of power pricing to natural gas pricing. (5) Each warrant is convertible into one share of Dynegy common stock. The following table summarizes our cash collateral posted as of December 31, 2017 and 2016 , 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, 2017 December 31, 2016 (amounts in millions) Gross collateral posted with counterparties $ 92 $ 116 Less: Collateral netted against risk management liabilities 47 54 Net collateral within Prepayments and other current assets $ 45 $ 62
Schedule of Derivative Instruments in the Balance Sheet, Fair Value	The following tables present the fair value and balance sheet classification of derivatives in our consolidated balance sheets as of December 31, 2017 and 2016 . As of December 31, 2017 and 2016 , there were no gross amounts available to be offset that were not offset in our consolidated balance sheets. December 31, 2017 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 $ 155 $ (112 ) $ — $ 43 Interest rate contracts Assets from risk management activities 20 (5 ) — 15 Total derivative assets $ 175 $ (117 ) $ — $ 58 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (411 ) $ 112 $ 47 $ (252 ) Interest rate contracts Liabilities from risk management activities (13 ) 5 — (8 ) Common stock warrants Accrued liabilities and other current liabilities and other long-term liabilities (2 ) — — (2 ) Total derivative liabilities $ (426 ) $ 117 $ 47 $ (262 ) Total derivatives $ (251 ) $ — $ 47 $ (204 ) 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
Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations	Our consolidated statements of operations for the years ended December 31, 2017, 2016 and 2015 include the impact of derivative financial instruments as presented below. Derivatives Not Designated as Hedges Location of Gain (Loss) Recognized in Income on Derivatives Year Ended December 31, 2017 2016 2015 (amounts in millions) Commodity contracts Revenues $ (58 ) $ 270 $ 194 Interest rate contracts Interest expense $ 16 $ (5 ) $ (15 ) Common stock warrants Other income and (expense), net $ 16 $ 6 $ 54

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring 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, 2017 and 2016 , 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, 2017 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 71 $ 6 $ 77 Natural gas derivatives — 62 10 72 Physical heat rate derivatives — 4 — 4 Emissions derivatives — 2 — 2 Total assets from commodity risk management activities — 139 16 155 Assets from interest rate contracts — 20 — 20 Total assets $ — $ 159 $ 16 $ 175 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (200 ) $ (31 ) $ (231 ) Natural gas derivatives — (71 ) (6 ) (77 ) Physical heat rate derivatives — (99 ) — (99 ) Heat rate option — — (4 ) (4 ) Total liabilities from commodity risk management activities — (370 ) (41 ) (411 ) Liabilities from interest rate contracts — (13 ) — (13 ) Liabilities from outstanding common stock warrants (2 ) — — (2 ) Total liabilities $ (2 ) $ (383 ) $ (41 ) $ (426 ) 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 )
Fair Value Inputs, Instruments Classified in Shareholders' Equity, Quantitative Information	The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of December 31, 2017 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) (14 ) Million MWh $ (23 ) Basis spread + liquid location Basis spread $4.25 - $6.25 FTRs (22 ) Million MWh $ (2 ) Historical congestion Forward price $0 - $6.00 Physical heat rate derivatives 4/0 Million MMBtu $ — Discounted Cash Flow Forward price $2.00 - $2.80 / $22 - $27 Heat rate option 6/1 Million MMBtu $ (4 ) Option models Power price volatility 30% - 50% / 70% - 100% Natural gas derivatives (1) 95 Million MMBtu $ 4 Illiquid location fixed price Forward price $2.00 - $2.45 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts.
Schedule of Changes in Fair Value of Derivatives	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, 2017 (amounts in millions) Electricity Natural Gas Derivatives Heat Rate Option Total Balance at December 31, 2016 $ 8 $ (6 ) $ — $ 2 Total gains (losses) included in earnings (30 ) 5 — (25 ) Settlements (1) (4 ) 5 — 1 Option premiums received — — (4 ) (4 ) Acquired derivatives 1 — — 1 Balance at December 31, 2017 $ (25 ) $ 4 $ (4 ) $ (25 ) Unrealized gains (losses) relating to instruments held as of December 31, 2017 $ (30 ) $ 5 $ — $ (25 ) Year Ended December 31, 2016 (amounts in millions) Electricity 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 Acquired derivatives (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 __________________________________________ (1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.
Fair Value of Receivables and Debt	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, 2017 and 2016 , respectively. December 31, 2017 December 31, 2016 (amounts in millions) Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: Term Loan, due 2024 (1) Level 2 $ (1,944 ) $ (2,021 ) $ (2,213 ) $ (2,250 ) Revolving Facility (1) Level 2 $ — $ — $ — $ — 6.75% Senior Notes, due 2019 (1) Level 2 $ (845 ) $ (873 ) $ (2,083 ) $ (2,137 ) 7.375% Senior Notes, due 2022 (1) Level 2 $ (1,734 ) $ (1,844 ) $ (1,731 ) $ (1,665 ) 5.875% Senior Notes, due 2023 (1) Level 2 $ (493 ) $ (508 ) $ (492 ) $ (431 ) 7.625% Senior Notes, due 2024 (1) Level 2 $ (1,237 ) $ (1,344 ) $ (1,237 ) $ (1,156 ) 8.034% Senior Notes, due 2024 (1) Level 2 $ (188 ) $ (198 ) $ — $ — 8.00% Senior Notes, due 2025 (1) Level 2 $ (739 ) $ (812 ) $ (738 ) $ (703 ) 8.125% Senior Notes, due 2026 (1) Level 2 $ (842 ) $ (933 ) $ — $ — 7.00% Amortizing Notes, due 2019 (TEUs) (1) Level 2 $ (51 ) $ (54 ) $ (78 ) $ (90 ) Forward capacity agreement (1) Level 3 $ (215 ) $ (215 ) $ (205 ) $ (205 ) Inventory financing agreements Level 3 $ (48 ) $ (48 ) $ (129 ) $ (127 ) Equipment financing agreements (1) Level 3 $ (97 ) $ (97 ) $ (73 ) $ (73 ) Genco: Liabilities subject to compromise (2) Level 3 $ — $ — $ (825 ) $ (366 ) __________________________________________ (1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion. (2) Carrying amounts represent the Genco senior notes that were 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 20—Genco Chapter 11 Bankruptcy for further details.

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2017
Supplemental Cash Flow Elements [Abstract]
Supplemental Disclosure of Cash Flow and Non-cash Investing and Financing Information	The supplemental disclosures of cash flow and non-cash investing and financing information are as follows: Year Ended December 31, (amounts in millions) 2017 2016 2015 Interest paid (net of amount capitalized of $2, $10, and $12, respectively) $ 555 $ 548 $ 491 Taxes paid (net of refunds) $ (5 ) $ (1 ) $ 2 Other non-cash investing and financing activity: Change in capital expenditures included in accounts payable $ 7 $ (13 ) $ (8 ) Change in capital expenditures pursuant to equipment financing agreements $ 24 $ 11 $ 63 Issuance of 2017 Warrants $ 17 $ — $ — Issuance of senior notes related to the Genco restructuring $ 188 $ — $ — Sale of interest in Conesville facility $ (58 ) $ — $ — Acquisition of interest in Zimmer facility $ 27 $ — $ — Non-cash consideration transferred for acquisitions $ — $ — $ 105

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2017
Inventory Disclosure [Abstract]
Summary of inventories	A summary of our inventories is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Materials and supplies $ 242 $ 182 Coal 166 238 Fuel oil 15 17 Natural gas 9 — Emissions allowances (1) 13 8 Total $ 445 $ 445 __________________________________________ (1) At December 31, 2017 and December 31, 2016 , a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt —Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	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 1 to 40 Office and other equipment 1 to 28 A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Power generation $ 9,998 $ 7,537 Buildings and improvements 955 944 Office and other equipment 115 98 Property, plant and equipment 11,068 8,579 Accumulated depreciation (2,184 ) (1,458 ) Property, plant and equipment, net $ 8,884 $ 7,121
Interest Costs Incurred and Interest Capitalized for Construction in Progress	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) 2017 2016 2015 Total interest costs incurred $ 576 $ 556 $ 487 Capitalized interest $ 2 $ 10 $ 12
Impairment Charges	During the years ended December 31, 2017, 2016 and 2015 , we recognized the following impairments in our consolidated statements of operations (amounts in millions). Facility Fair Value 2017 2016 2015 Baldwin (1) $ 97 $ — $ 645 $ — Stuart (2) $ — — 56 — Newton FGD (3) $ — — 148 — Killen (4) $ — 20 — — Hennepin (1) $ 16 10 — — Havana (1) $ 37 89 — — Wood River (5) $ — — — 74 Brayton Point (6) $ 86 — — 25 Total PP&E Impairments $ 119 $ 849 $ 99 Inventory $ — 14 — — Equity investment $ 173 — 9 — Assets held-for-sale, including $9 of allocated goodwill $ 176 15 — — Total Impairments $ 148 $ 858 $ 99 _________________________________________ (1) Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. As part of our impairment analysis, we changed the remaining useful lives of certain of our facilities. (2) We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model. (3) We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The impairment charge was equal to the capitalized cost of the project. (4) In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. As a result, the DCF model for the facility indicated negative cash flows, resulting in an impairment charge equal to its book value. (5) Primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market and increased environmental costs. The impairment was measured using a DCF model. (6) Temperate weather had a significant impact on the facility’s remaining cash flows, as the facility retired in May 2017. The impairment was measured using a DCF model.

Joint Ownership of Generating38

Joint Ownership of Generating Facilities (Tables)	12 Months Ended
	Dec. 31, 2017
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following tables present the ownership interests of the jointly owned facilities as of December 31, 2017 and 2016 included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2017 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Stuart (1)(2) 39.0 % $ 1 $ — $ — $ 1 Killen (1)(2) 33.0 % $ — $ — $ — $ — 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 __________________________________________ (1) Facilities not operated by Dynegy. (2) Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018.

Intangible Assets and Liabili39

Intangible Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Intangible Assets and Liabilities	The following table summarizes the components of our intangible assets and liabilities as of December 31, 2017 and 2016 : December 31, 2017 December 31, 2016 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 178 $ (131 ) $ 47 $ 260 $ (206 ) $ 54 Gas transport contracts 30 (13 ) 17 13 (6 ) 7 Total intangible assets $ 208 $ (144 ) $ 64 $ 273 $ (212 ) $ 61 Intangible Liabilities: Electricity contracts $ (11 ) $ 7 $ (4 ) $ (28 ) $ 26 $ (2 ) Coal contracts — — — (49 ) 42 (7 ) Coal transport contracts (48 ) 44 (4 ) (86 ) 73 (13 ) Gas transport contracts (58 ) 19 (39 ) (41 ) 8 (33 ) Gas storage contracts (2 ) 1 (1 ) — — — Total intangible liabilities $ (119 ) $ 71 $ (48 ) $ (204 ) $ 149 $ (55 ) Intangible assets and liabilities, net $ 89 $ (73 ) $ 16 $ 69 $ (63 ) $ 6 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the years ended December 31, 2017, 2016 and 2015 : Year Ended December 31, (amounts in millions) 2017 2016 2015 Electricity contracts, net (1) $ 32 $ 70 $ 75 Coal contracts, net (2) (5 ) (41 ) (60 ) Coal transport contracts, net (2) (9 ) (27 ) (32 ) Gas transport contracts, net (2) (5 ) 19 6 Gas storage contracts, net (2) (1 ) — — Total $ 12 $ 21 $ (11 ) __________________________________________ (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, 2017 is as follows: 2018 — $11 million , 2019 — $17 million , 2020 — $2 million , 2021 — ($3) million , and 2022 — ($4) million . The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017: (amounts in millions) Gross Carrying Amount Weighted-Average Amortization Period (months) Intangible Assets: Electricity contracts $ 34 39 Gas transport contracts 16 47 Total intangible assets $ 50 41 Intangible Liabilities: Electricity contracts $ (11 ) 32 Gas contracts — 1 Gas transport contracts (17 ) 35 Gas storage contracts (2 ) 13 Total intangible liabilities $ (30 ) 33 Total intangible assets and liabilities, net $ 20

Tangible Equity Units (Tables)

Tangible Equity Units (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of Tangible Equity Units	In 2016, 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

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	A summary of our long-term debt is as follows: (amounts in millions) December 31, 2017 December 31, 2016 Secured Obligations: Term Loan, due 2024 $ 2,018 $ 2,224 Revolving Facility — — Forward Capacity Agreement 241 219 Inventory Financing Agreements 48 129 Subtotal secured obligations 2,307 2,572 Unsecured Obligations: 7.00% Amortizing Notes, due 2019 (TEUs) 53 80 6.75% Senior Notes, due 2019 850 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 8.034% Senior Notes, due 2024 188 — 8.00% Senior Notes, due 2025 750 750 8.125% Senior Notes, due 2026 850 — Equipment Financing Agreements 132 97 Subtotal unsecured obligations 6,323 6,527 Total debt obligations 8,630 9,099 Unamortized debt discounts and issuance costs (197 ) (120 ) 8,433 8,979 Less: Current maturities, including unamortized debt discounts and issuance costs, net 105 201 Total long-term debt $ 8,328 $ 8,778
Schedule of Maturities of Long-term Debt	Aggregate maturities of the principal amounts of all indebtedness, excluding unamortized discounts, as of December 31, 2017 are as follows: (in millions) 2018 $ 115 2019 971 2020 136 2021 59 2022 1,760 Thereafter 5,589 Total $ 8,630

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Our components of income tax benefit related to losses from continuing operations were as follows: Year Ended December 31, (amounts in millions) 2017 2016 2015 Current tax benefit (expense) $ 233 $ 15 $ (3 ) Deferred tax benefit 377 30 477 Income tax benefit $ 610 $ 45 $ 474
Schedule of Income Taxes Included in Operating Operations	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) 2017 2016 2015 Expected tax benefit at U.S. statutory rate (35%) $ 189 $ 451 $ 149 State taxes 35 16 68 Permanent differences (1) (21 ) (4 ) 16 Non-deductible goodwill (10 ) — — Valuation allowance (2)(3) 879 (404 ) 271 NOL adjustments from use limitations (13 ) (17 ) — Adjustment to AMT credits (17 ) — (26 ) Change in federal tax rate as included in TCJA (429 ) — — Other (3 ) 3 (4 ) Income tax benefit $ 610 $ 45 $ 474 __________________________________________ (1) Permanent items for years ended December 31, 2017, 2016 and 2015 included a benefit of less than $1 million , a benefit of $2 million , and a benefit of $18 million , 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 years ended December 31, 2017 and 2016 includes $8 million and $5 million , respectively, of income tax expense for non-deductible fees related to the Genco Plan. Please read Note 20—Genco Chapter 11 Bankruptcy for further discussion. Income tax benefit for the year ended December 31, 2017 , includes $22 million for non-deductible legal fees related to the ENGIE Acquisition. (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) The ENGIE Acquisition on February 7, 2017 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $354 million reduction to our valuation allowance in 2017. We also recorded a benefit for the repeal of the corporate AMT in the amount of $223 million as included in the TCJA.
Schedule of Deferred Tax Assets and Liabilities	Our significant components of deferred tax assets and liabilities were as follows: Year Ended December 31, (amounts in millions) 2017 2016 Non-current deferred tax assets: NOL carryforwards $ 1,195 $ 1,629 AMT, state, and other tax credit carryforwards 25 241 Reserves (legal, environmental and other) 4 7 Pension and other post-employment benefits 11 18 Asset retirement obligations 68 85 Deferred financing costs and intangible/other contracts 22 48 Derivative contracts 69 57 Other 29 46 Subtotal 1,423 2,131 Less: valuation allowance (852 ) (1,704 ) Total non-current deferred tax assets $ 571 $ 427 Non-current deferred tax liabilities: Depreciation and other property differences $ (560 ) $ (371 ) Derivative contracts (7 ) (44 ) Other (11 ) (17 ) Total non-current deferred tax liabilities $ (578 ) $ (432 ) Net non-current deferred tax liabilities $ (7 ) $ (5 )
Summary of Valuation Allowance	The changes in the valuation allowance were as follows: Year Ended December 31, 2017 2016 2015 Beginning of period $ 1,704 $ 1,276 $ 1,535 Changes in valuation allowance—continuing operations: Charged to costs and expenses (854 ) 428 (259 ) Charged to other accounts 2 — — End of period $ 852 $ 1,704 $ 1,276
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of our beginning and ending amounts of unrecognized tax benefits were as follows: Year Ended December 31, amounts in millions 2017 2016 2015 Unrecognized tax benefits, beginning of period $ 3 $ 3 $ 4 Increase due to ENGIE acquisition 63 — — Decrease due to rate changes (26 ) — — Decrease due to settlements and payments — — (1 ) Unrecognized tax benefits, end of period $ 40 $ 3 $ 3

Stockholders' Equity (Tables)

Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Schedule of Common Stock Outstanding Roll Forward	The following table reflects balances and activity in our outstanding shares of common stock, for the years ended December 31, 2017, 2016 and 2015 : Shares outstanding balance as of December 31, (in millions) 2017 2016 2015 Shares outstanding at the beginning of the period 117 117 124 Shares issued under the PIPE Transaction 14 — — Shares issued as consideration for the EquiPower Acquisition — — 3 Shares repurchases (in treasury) — — (11 ) Shares issued from conversion of preferred stock 13 — — Shares issued under long-term compensation plans — — 1 Shares outstanding at the end of period 144 117 117
Schedule of Share-based Compensation, Stock Options, Activity	The following summarizes our stock option activity: Year Ended December 31, 2017 Options (in thousands) Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in years) Aggregate Intrinsic Value Outstanding at beginning of period 2,805 $ 18.69 Granted 1,454 $ 8.02 Forfeited (10 ) $ 27.24 Expired (42 ) $ 21.79 Outstanding at end of period 4,207 $ 14.95 7.65 $ 6.4 Vested and unvested expected to vest 4,207 $ 14.95 7.65 $ 6.4 Exercisable at end of period 2,023 $ 20.02 6.40 $ 0.5
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions	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, 2017 2016 2015 Dividend Yield $ — $ — $ — Expected volatility (1) 48.50 % 41.19 % 27.70 % Risk-free interest rate (2) 2.07 % 1.42 % 1.64 % Expected option life (3) 5.5 years 5.5 years 5.5 years Weighted average grant-date fair value $ 3.71 $ 4.37 $ 7.93 __________________________________________ (1) For the years ended December 31, 2017, 2016 and 2015 , 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.
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity	The following summarizes our RSU activity, including both those settled in shares and those settled in cash: Year Ended December 31, 2017 RSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 2,717 $ 16.11 Granted 3,177 $ 7.99 Vested and released (1,241 ) $ 19.04 Forfeited (107 ) $ 11.08 Outstanding at end of period 4,546 $ 9.75 The following summarizes our PSU activity: Year Ended December 31, 2017 PSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 1,221 $ 16.48 Granted 583 $ 8.02 Vested and released (3 ) $ 26.66 Forfeited (186 ) $ 23.10 Outstanding at end of period 1,615 $ 12.65
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	For the years ended December 31, 2017, 2016 and 2015 , 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) 2017 2016 2015 Stock options 2.8 2.8 0.5 Restricted stock units — 1.3 — Performance stock units — 1.2 — Warrants (1) 9.0 15.6 15.6 Series A 5.375% mandatory convertible preferred stock (2) — 12.9 12.9 TEUs — 5.4 — Total 11.8 39.2 29.0 _________________________________________ (1) During 2017, we issued 9.0 million warrants to eligible holders of Genco senior notes as a result of the Genco Chapter 11 Bankruptcy. Warrants to purchase 15.6 million shares of our Common Stock expired on October 2, 2017. (2) On November 1, 2017, our outstanding Preferred Stock was converted to approximately 12.9 million shares of Common Stock.
Schedule of Weighted Average Number of Shares	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, 2017, 2016 and 2015 : Year Ended December 31, (in millions, except per share amounts) 2017 2016 2015 Shares outstanding at the beginning of the period 140 117 124 Weighted-average shares during the period of: Shares issuances 13 — 4 Shares converted from preferred stock 2 — — Shares repurchases — — (3 ) Prepaid stock purchase contract (TEUs) (1) — 12 — Basic weighted-average shares 155 129 125 Dilution from potentially dilutive shares (2) 7 — 1 Diluted weighted-average shares (3) 162 129 126 _________________________________________ (1) The minimum settlement amount, or 23.1 million 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 12—Tangible Equity Units for further discussion. (2) Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of: • 5.4 million additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount ( 28.5 million shares); and • 1.9 million additional shares attributable to restricted stock units and performance stock units. (3) 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 year ended December 31, 2016.
Schedule of 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) 2017 2016 2015 Beginning of period $ 21 $ 19 $ 20 Other comprehensive income before reclassifications: Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively) 19 2 3 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) (8 ) (5 ) (4 ) Net current period other comprehensive income (loss), net of tax 11 2 (1 ) End of period $ 32 $ 21 $ 19 __________________________________________ (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 17—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 17—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments and Contingencies Disclosure [Abstract]
Lessee, Operating Lease, Disclosure	Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases per year for the years 2018-2022 are as follows: (in millions) 2018 $ 6 2019 $ 5 2020 $ 5 2021 $ 5 2022 $ 4

Employee Compensation, Saving45

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2017
Retirement Benefits [Abstract]
Schedule of Defined Benefit Plans Disclosures	Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2017 2016 Benefit obligation, beginning of the year $ 508 $ 483 $ 42 $ 74 Service cost 17 16 — 1 Interest cost 20 20 2 3 Actuarial loss 28 23 1 4 Benefits paid (36 ) (32 ) (4 ) (6 ) Plan change (10 ) (2 ) (1 ) (17 ) Settlements — — — (17 ) Acquisitions — — — — Divestitures — — — — Benefit obligation, end of the year $ 527 $ 508 $ 40 $ 42 Fair value of plan assets, beginning of the year $ 415 $ 410 $ 49 $ 67 Actual return on plan assets 65 37 4 2 Employer contributions 4 — — — Benefits paid (36 ) (32 ) (2 ) (3 ) Settlements — — — (17 ) Acquisitions — — — — Divestitures — — — — Transfers Out (1) — — (19 ) — Fair value of plan assets, end of the year $ 448 $ 415 $ 32 $ 49 Funded status $ (79 ) $ (93 ) $ (8 ) $ 7 __________________________________________ (1) As permitted by EEI’s other post-employment plan for EEI union employees, part of the overfunded portion of the plan assets was segregated in 2017 to offset the employer cost of the active EEI employees’ health and welfare benefits.
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized in the consolidated balance sheets consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2017 2016 Non-current assets $ — $ 7 $ 33 $ 32 Current liabilities — — (2 ) (2 ) Non-current liabilities (79 ) (100 ) (20 ) (23 ) Net amount recognized $ (79 ) $ (93 ) $ 11 $ 7
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2018 are as follows: (amounts in millions) Pension Benefits Other Benefits Prior service credit $ (3 ) $ (5 ) Actuarial gain — (1 ) $ (3 ) $ (6 ) Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2017 2016 Prior service credit $ (19 ) $ (12 ) $ (43 ) $ (47 ) Actuarial loss (gain) (8 ) 2 1 1 Net gain recognized $ (27 ) $ (10 ) $ (42 ) $ (46 )
Schedule of Net Benefit Costs	The components of net periodic benefit cost (gain) were as follows: Pension Benefits Year Ended December 31, (amounts in millions) 2017 2016 2015 Service cost benefits earned during period $ 17 $ 16 $ 14 Interest cost on projected benefit obligation 20 20 18 Expected return on plan assets (25 ) (22 ) (23 ) Amortization of: Prior service credit (2 ) (1 ) (1 ) Actuarial gain — — — Net periodic benefit cost $ 10 $ 13 $ 8 Other Benefits Year Ended December 31, (amounts in millions) 2017 2016 2015 Service cost benefits earned during period $ — $ 1 $ 1 Interest cost on projected benefit obligation 2 3 4 Expected return on plan assets (2 ) (4 ) (4 ) Amortization of: Prior service credit (5 ) (4 ) (3 ) Actuarial gain (1 ) — — Net periodic benefit gain (6 ) (4 ) (2 ) Settlement cost (1) — 6 — Total benefit cost (gain) $ (6 ) $ 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.
Schedule of Assumptions Used	The following weighted average assumptions were used to determine benefit obligations: Pension Benefits Other Benefits Year Ended December 31, 2017 2016 2017 2016 Discount rate (1) 3.60 % 4.05 % 3.55 % 4.00 % 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, 2017 2016 2015 2017 2016 2015 Discount rate 3.60 % 4.05 % 4.35 % 3.55 % 4.00 % 4.35 % Dynegy - Expected return on plan assets 6.20 % 5.60 % 5.70 % N/A N/A N/A EEI - Expected return on plan assets (1) 6.40 % 5.90 % 6.00 % 5.75 % 5.40 % 5.50 % 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 5.75 percent , 5.40 percent , and 5.50 percent for the years ended December 31, 2017, 2016 and 2015 , respectively. The expected return on EEI’s other post-employment plan assets was 6.90 percent , 6.30 percent , and 6.20 percent for EEI union employees for the years ended December 31, 2017, 2016 and 2015 , respectively. The expected return on EEI’s other post-employment plan assets was 4.60 percent , 4.50 percent , and 4.80 percent for EEI salaried employees for the years ended December 31, 2017, 2016 and 2015 , respectively. (2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2017, 2016 and 2015 is specifically related to the EEI post-employment plans.
Schedule of Health Care Cost Trend Rates	The following summarizes our assumed health care cost trend rates: Year Ended December 31, 2017 2016 2015 Health care cost trend rate assumed for next year 7.00 % 7.25 % 7.00 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2025 2025 2023
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	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 $ — $ — Impact on accumulated post-employment benefit obligation $ 3 $ (2 )
Fair Value Inputs, Assets, Quantitative Information	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, 2017 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 7 $ — $ — $ 7 Equity securities: U.S. companies (1) 14 136 — 150 Non-U.S. companies (2) 1 19 — 20 International (3) 9 62 — 71 Fixed income securities (4) 63 169 — 232 Total $ 94 $ 386 $ — $ 480 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 Total $ 101 $ 365 $ — $ 466 ________________________________________ (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.
Schedule of Expected Benefit Payments	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 2018 $ 39 $ 3 2019 $ 38 $ 3 2020 $ 38 $ 3 2021 $ 38 $ 3 2022 $ 38 $ 2 2023 - 2027 $ 190 $ 11

Quarterly Financial Informati46

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Schedule of 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 2017 Revenues $ 1,247 $ 1,164 $ 1,437 $ 994 Operating income (loss) (1) $ (49 ) $ (182 ) $ 58 $ (239 ) Net income (loss) (2)(3)(4) $ 596 $ (296 ) $ (133 ) $ (95 ) Net income (loss) attributable to Dynegy Inc. common stockholders (2)(3)(4) $ 592 $ (302 ) $ (137 ) $ (95 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (2)(3)(4) $ 4.00 $ (1.96 ) $ (0.89 ) $ (0.58 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (2)(3)(4) $ 3.57 $ (1.96 ) $ (0.89 ) $ (0.58 ) 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 ) _____________________ (1) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include impairment charges of $20 million , $99 million , and $29 million , respectively. 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 8—Property, Plant and Equipment for more information. (2) The results for the quarters ended June 30, 2017, September 30, 2017, and December 31, 2017 include losses on sale of assets of $29 million , $78 million , and $15 million , respectively. See Note 3—Acquisitions and Divestitures and Note 9—Joint Ownership of Generating Facilities for more information. (3) The results for the quarters ended March 31, 2017, June 30, 2017, and September 30, 2017, include income (loss) from bankruptcy reorganization items of $483 million , ($1) million , and $12 million , respectively. The results for the quarter ended December 31, 2016 include loss from Bankruptcy reorganization items of $96 million . See Note 20—Genco Chapter 11 Bankruptcy for more information. (4) The results for the quarters ended March 31, 2017 and December 31, 2017 include a $317 million and $37 million income tax benefit, respectively, from the partial release of our valuation allowance as a result of the ENGIE Acquisition. The results for the quarter ended December 31, 2017 include a $223 million tax benefit related to the expected refund of its existing AMT Credits as provided for in the TCJA. See Note 14—Income Taxes for more information.

Condensed Consolidating Finan47

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2017
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheet for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 233 $ 124 $ 8 $ — $ 365 Accounts receivable, net 126 4,269 14 (3,896 ) 513 Inventory — 415 30 — 445 Other current assets 8 288 2 (97 ) 201 Total Current Assets 367 5,096 54 (3,993 ) 1,524 Property, plant and equipment, net — 8,585 299 — 8,884 Investment in affiliates 16,132 — — (16,132 ) — Investment in unconsolidated affiliates — 123 — — 123 Goodwill — 772 — — 772 Other long-term assets 244 185 39 — 468 Intercompany note receivable 46 — — (46 ) — Total Assets $ 16,789 $ 14,761 $ 392 $ (20,171 ) $ 11,771 Current Liabilities Accounts payable $ 3,555 $ 471 $ 232 $ (3,891 ) $ 367 Other current liabilities 156 520 108 (102 ) 682 Total Current Liabilities 3,711 991 340 (3,993 ) 1,049 Debt, long-term portion, net 8,045 256 27 — 8,328 Intercompany note payable 3,042 46 — (3,088 ) — Other long-term liabilities 90 367 44 — 501 Total Liabilities 14,888 1,660 411 (7,081 ) 9,878 Stockholders’ Equity Dynegy Stockholders’ Equity 1,901 16,151 (19 ) (16,132 ) 1,901 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 1,901 13,109 (19 ) (13,090 ) 1,901 Noncontrolling interest — (8 ) — — (8 ) Total Equity 1,901 13,101 (19 ) (13,090 ) 1,893 Total Liabilities and Equity $ 16,789 $ 14,761 $ 392 $ (20,171 ) $ 11,771 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 $ 221 $ 26 $ — $ 1,776 Restricted cash 21 41 — — 62 Accounts receivable, net 141 2,604 39 (2,398 ) 386 Inventory — 326 119 — 445 Other current assets 12 408 2 (104 ) 318 Total Current Assets 1,703 3,600 186 (2,502 ) 2,987 Property, plant and equipment, net — 6,772 349 — 7,121 Investment in affiliates 12,175 — — (12,175 ) — Restricted cash 2,000 — — — 2,000 Other long-term assets 2 109 35 — 146 Goodwill — 799 — — 799 Intercompany note receivable — 8 — (8 ) — Total Assets $ 15,880 $ 11,288 $ 570 $ (14,685 ) $ 13,053 Current Liabilities Accounts payable $ 1,990 $ 443 $ 297 $ (2,398 ) $ 332 Other current liabilities 143 377 168 (104 ) 584 Total Current Liabilities 2,133 820 465 (2,502 ) 916 Liabilities subject to compromise — 832 — — 832 Debt, long-term portion, net 8,531 216 31 — 8,778 Intercompany note payable 3,042 — — (3,042 ) — Other long-term liabilities 132 313 51 (8 ) 488 Total Liabilities 13,838 2,181 547 (5,552 ) 11,014 Stockholders’ Equity Dynegy Stockholders’ Equity 2,042 12,152 23 (12,175 ) 2,042 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,042 9,110 23 (9,133 ) 2,042 Noncontrolling interest — (3 ) — — (3 ) Total Equity 2,042 9,107 23 (9,133 ) 2,039 Total Liabilities and Equity $ 15,880 $ 11,288 $ 570 $ (14,685 ) $ 13,053
Condensed Consolidating Income Statement	Condensed Consolidating Statements of Operations for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 4,557 $ 422 $ (137 ) $ 4,842 Cost of sales, excluding depreciation expense — (2,790 ) (279 ) 137 (2,932 ) Gross margin — 1,767 143 — 1,910 Operating and maintenance expense — (881 ) (114 ) — (995 ) Depreciation expense — (757 ) (54 ) — (811 ) Impairments — (148 ) — — (148 ) Gain (loss) on sale of assets, net — (123 ) 1 — (122 ) General and administrative expense (28 ) (155 ) (6 ) — (189 ) Acquisition and integration costs (54 ) (3 ) — — (57 ) Operating loss (82 ) (300 ) (30 ) — (412 ) Bankruptcy reorganization items (18 ) 512 — — 494 Earnings from unconsolidated investments — 8 — — 8 Equity in losses from investments in affiliates 824 — — (824 ) — Interest expense (597 ) (20 ) (13 ) 14 (616 ) Loss on early extinguishment of debt (79 ) — — — (79 ) Other income and expense, net 28 53 — (14 ) 67 Income (loss) before income taxes 76 253 (43 ) (824 ) (538 ) Income tax benefit (Note 14) — 610 — — 610 Net income (loss) 76 863 (43 ) (824 ) 72 Less: Net loss attributable to noncontrolling interest — (4 ) — — (4 ) Net income (loss) attributable to Dynegy Inc. $ 76 $ 867 $ (43 ) $ (824 ) $ 76 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 3,942 $ 468 $ (92 ) $ 4,318 Cost of sales, excluding depreciation expense — (2,112 ) (261 ) 92 (2,281 ) Gross margin — 1,830 207 — 2,037 Operating and maintenance expense — (796 ) (144 ) — (940 ) Depreciation expense — (612 ) (77 ) — (689 ) Impairments — (858 ) — — (858 ) Gain (loss) on sale of assets, net (2 ) 1 — — (1 ) General and administrative expense (7 ) (148 ) (6 ) — (161 ) Acquisition and integration costs (10 ) (1 ) — — (11 ) Other — (9 ) (8 ) — (17 ) Operating loss (19 ) (593 ) (28 ) — (640 ) Bankruptcy reorganization items — (96 ) — — (96 ) Earnings from unconsolidated investments — 7 — — 7 Equity in losses from investments in affiliates (715 ) — — 715 — Interest expense (538 ) (83 ) (9 ) 5 (625 ) Other income and expense, net 32 38 — (5 ) 65 Loss before income taxes (1,240 ) (727 ) (37 ) 715 (1,289 ) Income tax benefit (Note 14) — 45 — — 45 Net loss (1,240 ) (682 ) (37 ) 715 (1,244 ) Less: Net loss attributable to noncontrolling interest — (4 ) — — (4 ) Net loss attributable to Dynegy Inc. $ (1,240 ) $ (678 ) $ (37 ) $ 715 $ (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 $ — $ 3,508 $ 525 $ (163 ) $ 3,870 Cost of sales, excluding depreciation expense — (1,874 ) (317 ) 163 (2,028 ) Gross margin — 1,634 208 — 1,842 Operating and maintenance expense — (717 ) (122 ) — (839 ) Depreciation expense — (505 ) (82 ) — (587 ) Impairments — (74 ) (25 ) — (99 ) Loss on sale of assets, net — (1 ) — — (1 ) General and administrative expense (6 ) (116 ) (6 ) — (128 ) Acquisition and integration costs — (124 ) — — (124 ) Operating income (loss) (6 ) 97 (27 ) — 64 Earnings from unconsolidated investments — 1 — — 1 Equity in earnings from investments in affiliates 476 — — (476 ) — Interest expense (475 ) (69 ) (4 ) 2 (546 ) Other income and expense, net 55 1 — (2 ) 54 Income (loss) before income taxes 50 30 (31 ) (476 ) (427 ) Income tax benefit (Note 14) — 472 2 — 474 Net income (loss) 50 502 (29 ) (476 ) 47 Less: Net income attributable to noncontrolling interest — (3 ) — — (3 ) Net income (loss) attributable to Dynegy Inc. $ 50 $ 505 $ (29 ) $ (476 ) $ 50
Condensed Statement of Comprehensive Income (Loss)	Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 76 $ 863 $ (43 ) $ (824 ) $ 72 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of $5 22 (3 ) — — 19 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (7 ) — (1 ) — (8 ) Other comprehensive loss from investment in affiliates (4 ) — — 4 — Other comprehensive income (loss), net of tax 11 (3 ) (1 ) 4 11 Comprehensive income (loss) 87 860 (44 ) (820 ) 83 Less: Comprehensive loss attributable to noncontrolling interest — (4 ) — — (4 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 87 $ 864 $ (44 ) $ (820 ) $ 87 Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (1,240 ) $ (682 ) $ (37 ) $ 715 $ (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 ) (681 ) (26 ) 703 (1,240 ) Less: Comprehensive income (loss) attributable to noncontrolling interest 2 (2 ) — (2 ) (2 ) Total comprehensive loss attributable to Dynegy Inc. $ (1,238 ) $ (679 ) $ (26 ) $ 705 $ (1,238 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 50 $ 502 $ (29 ) $ (476 ) $ 47 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of zero (8 ) 7 5 — 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 — 7 4 (11 ) — Comprehensive income (loss) 50 509 (25 ) (487 ) 47 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 (2 ) — (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 49 $ 511 $ (25 ) $ (486 ) $ 49
Condensed Consolidating Cash Flow Statement	Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2017 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (427 ) $ 899 $ 113 $ — $ 585 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (208 ) (16 ) — (224 ) Acquisitions, net of cash acquired/divestitures (3,244 ) (75 ) — — (3,319 ) Distributions from unconsolidated affiliate — 12 — — 12 Proceeds from sales of assets, net 775 (4 ) 1 — 772 Net intercompany transfers 691 — — (691 ) — Net cash used in investing activities (1,778 ) (275 ) (15 ) (691 ) (2,759 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 1,743 — — — 1,743 Repayments of borrowings (2,487 ) (46 ) (56 ) — (2,589 ) Proceeds from issuance of equity, net of issuance costs 150 — — — 150 Payments of debt extinguishment costs (50 ) — — — (50 ) Preferred stock dividends paid (22 ) — — — (22 ) Interest rate swap settlement payments (20 ) — — — (20 ) Acquisition of noncontrolling interest (375 ) — — — (375 ) Payments related to bankruptcy settlement (128 ) (5 ) — — (133 ) Net intercompany transfers — (631 ) (60 ) 691 — Intercompany borrowings, net of repayments 80 (80 ) — — — Other financing (3 ) — — — (3 ) Net cash provided by (used in) financing activities (1,112 ) (762 ) (116 ) 691 (1,299 ) Net decrease in cash and cash equivalents (3,317 ) (138 ) (18 ) — (3,473 ) Cash, cash equivalents and restricted cash, beginning of period 3,550 262 26 — 3,838 Cash, cash equivalents and restricted cash, end of period $ 233 $ 124 $ 8 $ — $ 365 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 $ (476 ) $ 1,090 $ 31 $ — $ 645 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (243 ) (50 ) — (293 ) Proceeds from sales of assets, net 171 5 — — 176 Distributions from unconsolidated affiliate — 14 — — 14 Net intercompany transfers 958 — — (958 ) — Other investing — 10 — — 10 Net cash provided by (used in) investing activities 1,129 (214 ) (50 ) (958 ) (93 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 2,816 198 — — 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 — (991 ) 33 958 — Other financing (3 ) — — — (3 ) Net cash provided by (used in) financing activities 2,570 (808 ) 22 958 2,742 Net increase in cash and cash equivalents 3,223 68 3 — 3,294 Cash, cash equivalents and restricted cash, beginning of period 327 194 23 — 544 Cash, cash equivalents and restricted cash, end of period $ 3,550 $ 262 $ 26 $ — $ 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 ) $ 682 $ (156 ) $ — $ 94 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (290 ) (11 ) — (301 ) Acquisitions, net of cash acquired/divestitures (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 ) (250 ) 89 (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 — (347 ) (103 ) 450 — Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (339 ) (292 ) (84 ) 450 (265 ) Net increase (decrease) in cash and cash equivalents (6,528 ) 140 (151 ) — (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 $ 194 $ 23 $ — $ 544

Genco Chapter 11 Bankruptcy (Ta

Genco Chapter 11 Bankruptcy (Tables)	12 Months Ended
	Dec. 31, 2017
Reorganizations [Abstract]
Schedule of Reorganization Items	The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our consolidated statement of operations for the year ended December 31, 2017 : (amounts in millions) Liabilities subject to compromise, which were terminated $ 832 Less: Seven-year unsecured notes 188 Cash consideration 122 2017 Warrants, at fair value 17 Legal and consulting fees 11 Bankruptcy reorganization items $ 494 A summary of our liabilities subject to compromise as of December 31, 2016 is as follows: (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

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2017, 2016 and 2015 is presented below: Segment Data as of and for the Year Ended December 31, 2017 (amounts in millions) PJM NY/NE ERCOT MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 2,352 $ 1,031 $ 276 $ 1,061 $ 122 $ — $ 4,842 Intercompany and affiliate revenues (90 ) (2 ) 1 91 — — — Total revenues $ 2,262 $ 1,029 $ 277 $ 1,152 $ 122 $ — $ 4,842 Depreciation expense $ (379 ) $ (224 ) $ (73 ) $ (75 ) $ (53 ) $ (7 ) $ (811 ) Impairments (49 ) — — (99 ) — — (148 ) Gain (loss) on sale of assets, net (36 ) (90 ) — 1 3 — (122 ) General and administrative expense — — — — — (189 ) (189 ) Acquisition and integration costs — — — — — (57 ) (57 ) Operating income (loss) $ 192 $ (113 ) $ (147 ) $ (44 ) $ (45 ) $ (255 ) $ (412 ) Bankruptcy reorganization items — — — 494 — — 494 Earnings from unconsolidated investments 3 5 — — — — 8 Interest expense — — — — — (616 ) (616 ) Loss on early extinguishment of debt — — — — — (79 ) (79 ) Other income and expense, net 16 — — 26 — 25 67 Loss before income taxes (538 ) Income tax benefit — — — — — 610 610 Net Income 72 Less: Net loss attributable to noncontrolling interest (4 ) Net Income attributable to Dynegy Inc. $ 76 Total assets—domestic $ 4,912 $ 3,374 $ 1,563 $ 812 $ 455 $ 655 $ 11,771 Investment in unconsolidated affiliate $ 67 $ 56 $ — $ — $ — $ — $ 123 Capital expenditures $ (103 ) $ (50 ) $ (26 ) $ (26 ) $ (12 ) $ (7 ) $ (224 ) Segment Data as of and for the Year Ended December 31, 2016 (amounts in millions) PJM NY/NE MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 2,147 $ 836 $ 1,165 $ 142 $ — $ 4,290 Intercompany revenues 55 1 (28 ) — — 28 Total revenues $ 2,202 $ 837 $ 1,137 $ 142 $ — $ 4,318 Depreciation expense $ (346 ) $ (215 ) $ (81 ) $ (42 ) $ (5 ) $ (689 ) Impairments (65 ) — (793 ) — — (858 ) Gain (loss) 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 ) $ (832 ) $ (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 benefit — — — — 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 $ 1,065 $ 485 $ 3,795 $ 13,053 Capital expenditures $ (160 ) $ (64 ) $ (52 ) $ (7 ) $ (10 ) $ (293 ) Segment Data as of and for the Year Ended December 31, 2015 (amounts in millions) PJM NY/NE MISO CAISO Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,708 $ 705 $ 1,279 $ 178 $ — $ 3,870 Intercompany revenues 8 (10 ) 2 — — — Total revenues $ 1,716 $ 695 $ 1,281 $ 178 $ — $ 3,870 Depreciation expense $ (281 ) $ (186 ) $ (68 ) $ (48 ) $ (4 ) $ (587 ) Impairments — (25 ) (74 ) — — (99 ) Loss on sale of assets, net — — — (1 ) — (1 ) General and administrative expense — — — — (128 ) (128 ) Acquisition and integration costs — — — — (124 ) (124 ) Operating income (loss) $ 423 $ (56 ) $ (43 ) $ (8 ) $ (252 ) $ 64 Earnings from unconsolidated investments 1 — — — — 1 Interest expense — — — — (546 ) (546 ) Other income and expense, net (2 ) — 1 — 55 54 Loss from continuing operations 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 $ 1,995 $ 534 $ 486 $ 11,459 Investment in unconsolidated affiliate $ 190 $ — $ — $ — $ — $ 190 Capital expenditures $ (106 ) $ (52 ) $ (119 ) $ (11 ) $ (13 ) $ (301 )
Schedule of Revenue by Major Customers by Reporting Segments	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, 2017, 2016 and 2015 are presented below: (amounts in millions) Revenues Customers 2017 2016 2015 Segment(s) PJM $ 1,313 $ 1,366 $ 1,088 PJM, MISO MISO $ 506 $ 688 $ 842 MISO ISO-NE $ 669 $ 437 N/A MISO, NY/NE

Organization and Operations (De

Organization and Operations (Details)	Oct. 29, 2017	Feb. 07, 2017USD ($)facility	Dec. 31, 2017USD ($)	Dec. 31, 2017USD ($)segment
Debt Instrument [Line Items]
Number of reportable segments | segment				5
Termination fee of terminating entity				$ 87,000,000
Termination fee of surviving entity				$ 100,000,000
Engie Acquisition
Debt Instrument [Line Items]
Natural gas power facilities acquired | facility		15
Cash		$ 3,300,000,000
Engie Acquisition | TEXAS
Debt Instrument [Line Items]
Coal-fired power facilities | facility		1
Engie Acquisition | PENNSYLVANIA
Debt Instrument [Line Items]
Coal-fired power facilities | facility		1
Vistra Energy Merger
Debt Instrument [Line Items]
Number of acquiring entity shares to be received, ratio	0.652
Vistra Energy Merger | Vistra Energy Corp. | Vistra Energy Shareholders
Debt Instrument [Line Items]
Percentage of ownership after transaction	79.00%
Acquisition costs			$ 17,000,000
Vistra Energy Merger | Vistra Energy Corp. | Dynegy Shareholders
Debt Instrument [Line Items]
Percentage of ownership after transaction	21.00%

Summary of Significant Accoun51

Summary of Significant Accounting Policies - Noncontrolling Interest (Details)	Dec. 31, 2017
Electric Energy, Inc
Noncontrolling Interest [Line Items]
Noncontrolling interest of Electric Energy, Inc.	20.00%

Summary of Significant Accoun52

Summary of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Millions	Dec. 31, 2017	Feb. 07, 2017	Dec. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Cash deposits associated with certain letters of credit			$ 41	$ 39
Pre-funded original issue discount on the Term Loan			20
Interest earned on funds in escrow			1
Restricted cash			62
Restricted cash, long-term	$ 0		$ 2,000	$ 0
Deposits returned to Dynegy		$ 35

Summary of Significant Accoun53

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2017USD ($)
Property, Plant and Equipment [Line Items]
Goodwill, impairment	$ 0
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Property, Plant and Equipment [Line Items]
Goodwill, written off related to sale of business unit	$ 27,000,000
Minimum
Property, Plant and Equipment [Line Items]
Useful lives	1 year
Maximum
Property, Plant and Equipment [Line Items]
Useful lives	40 years
Power generation | Minimum
Property, Plant and Equipment [Line Items]
Useful lives	1 year
Power generation | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	36 years
Buildings and improvements | Minimum
Property, Plant and Equipment [Line Items]
Useful lives	1 year
Buildings and improvements | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	40 years
Office and miscellaneous equipment | Minimum
Property, Plant and Equipment [Line Items]
Useful lives	1 year
Office and miscellaneous equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful lives	28 years

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Changes in AROs
Balance at beginning of year	$ 287	$ 280
Accretion expense	20	20
Liabilities settled	(8)	(1)
Revision of previous estimate	22	(12)
Acquisitions	24	0
Divestitures	(16)	0
Balance at end of year	$ 329	$ 287

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Preferred Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Nov. 01, 2017	Oct. 02, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Conversion of convertible securities (in shares)	12.9
Dividends paid			$ 22	$ 22	$ 23
Preferred Stock
Class of Stock [Line Items]
Preferred stock, dividends declared (in dollars per share)		$ 1.34
Dividends paid		$ 5

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Income Taxes (Details)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Percent of largest amount of benefit upon settlement	50.00%

Summary of Significant Accoun57

Summary of Significant Accounting Policies - Accounting Standards Updates (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net cash provided by (used in) operating activities	$ 585	$ 645	$ 94
Net cash provided by (used in) investing activities	(2,759)	(93)	(6,368)
Cash and cash equivalents	365	1,776	505
Restricted cash	0	62	39
Restricted cash	0	2,000	0
Total cash, cash equivalents and restricted cash	$ 365	3,838	544	$ 7,083
Collateral		41	39
Escrow deposit		21
Pre-funded original issue discount on the Term Loan		20
Interest earned on funds in escrow		1
Accounting Standards Update 2016-15
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net cash provided by (used in) operating activities		(33)	26
Accounting Standards Update 2016-18
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net cash provided by (used in) operating activities		(2)	(26)
Net cash provided by (used in) investing activities		(2,021)	(5,148)
Restricted cash and cash equivalents		$ 2,062	$ 39	$ 5,213

Acquisitions and Divestitures -

Acquisitions and Divestitures - Textual (Details) $ in Millions	Apr. 12, 2017USD ($)	Feb. 07, 2017USD ($)facilityMW	Apr. 02, 2015USD ($)facilityAffiliateMW	Apr. 01, 2015USD ($)facilityMW	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Other income and expense, net | $					$ 67	$ 65	$ 54
Brayton Point
Business Acquisition [Line Items]
Percent of voting interests acquired				100.00%
GDF Suez Energy North America
Business Acquisition [Line Items]
Power acquired (MW) | MW		9,017
Natural gas power facilities acquired		15
Coal-fired power facilities		1
Cash | $		$ 3,300
Engie Acquisition
Business Acquisition [Line Items]
Natural gas power facilities acquired		15
Cash | $		$ 3,300
Long-term revenue growth rate		2.50%
Long-term expense growth rate, after year five		2.50%
Engie Acquisition | Gas | Minimum
Business Acquisition [Line Items]
Discount rate		9.00%
Engie Acquisition | Gas | Maximum
Business Acquisition [Line Items]
Discount rate		13.00%
Engie Acquisition | Coal | Minimum
Business Acquisition [Line Items]
Discount rate		13.00%
Engie Acquisition | Coal | Maximum
Business Acquisition [Line Items]
Discount rate		14.00%
ERC Purchase Agreement
Business Acquisition [Line Items]
Natural gas power facilities acquired				1
Coal-fired power facilities				1
Percent of voting interests acquired				100.00%
Combined cycle gas facilities acquired				5
EquiPower Acquisition
Business Acquisition [Line Items]
Power acquired (MW) | MW				6,300
Cash | $				$ 3,350
Gas and oil power facilities acquired				2
Equity interests issued and issuable | $				$ 105
Duke Midwest Purchase Agreement
Business Acquisition [Line Items]
Power acquired (MW) | MW			6,200
Natural gas power facilities acquired			2
Cash | $			$ 2,800
Percent of voting interests acquired			100.00%
Combined cycle gas facilities acquired			3
Number of affiliates | Affiliate			2
Retail energy business acquired			1
ENGIE, EquiPower, and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Acquisition costs | $					$ 38	5	$ 86
Duke Midwest Acquisition | Coal
Business Acquisition [Line Items]
Coal-fired power facilities			5
Oil-fired power facilities			1
AER Acquisition
Business Acquisition [Line Items]
Change in amount of contingent consideration, liability | $	$ 25					14
Other income and expense, net | $	$ 25					$ 14

Acquisitions and Divestitures59

Acquisitions and Divestitures - Schedule of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions	Feb. 07, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Fair value of total consideration transferred		$ 0	$ 0	$ 105
Engie Acquisition
Business Acquisition [Line Items]
Cash	$ 3,300
Net working capital adjustment	(31)
Fair value of total consideration transferred	3,269
Assets Acquired
Cash	20
Accounts receivable	22
Inventory	95
Prepayments and other current assets	3
Assets from risk management activities (including current portion)	25
Assets from risk management activities, current portion	21
Property, plant and equipment	2,775
Investment in unconsolidated affiliate	132
Intangible assets (including current portion)	50
Intangible assets, current portion	7
Assets held-for-sale	472
Other long-term assets	131
Total assets acquired	3,725
Liabilities Assumed
Accounts payable	18
Liabilities from risk management activities (including current portion)	16
Liabilities from risk management activities, current portion	13
Asset retirement obligations	19
Intangible liabilities (including current portion)	30
Intangible liabilities, current portion	16
Deferred income taxes, net	372
Other long-term liabilities	1
Total liabilities assumed	456
Net assets acquired	$ 3,269

Acquisitions and Divestitures60

Acquisitions and Divestitures - Acquisition Related Costs (Details) - ENGIE, EquiPower, and Duke Midwest Acquisitions - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Acquisition costs	$ 38	$ 5	$ 86
Revenues	3,079	2,280	1,703
Operating income	$ 86	$ 235	$ 230

Acquisitions and Divestitures61

Acquisitions and Divestitures - Schedule of Pro Forma Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
ENGIE, EquiPower, and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Revenue	$ 4,899	$ 5,046
Net income (loss) from continuing operations	77	(1,361)
ENGIE, EquiPower, and Duke Midwest Acquisitions | Noncontrolling Interest
Business Acquisition [Line Items]
Net income (loss) from continuing operations	(4)	(4)
ENGIE, EquiPower, and Duke Midwest Acquisitions | Dynegy Inc
Business Acquisition [Line Items]
Net income (loss) from continuing operations	$ 81	$ (1,357)
EquiPower and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Revenue			$ 4,860
Net income (loss) from continuing operations			308
EquiPower and Duke Midwest Acquisitions | Noncontrolling Interest
Business Acquisition [Line Items]
Net income (loss) from continuing operations			(3)
EquiPower and Duke Midwest Acquisitions | Dynegy Inc
Business Acquisition [Line Items]
Net income (loss) from continuing operations			$ 311

Acquisitions and Divestitures62

Acquisitions and Divestitures - Divestitures (Details) $ in Millions	Oct. 12, 2017USD ($)	Sep. 22, 2017USD ($)facility	Jul. 11, 2017USD ($)facilityMW	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of assets, net				$ (15)	$ (78)	$ (29)	$ 122	$ 1	$ 1
Goodwill, discontinued operation				$ 9			9
Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Goodwill, written off related to sale of business unit							27
Troy and Armstrong | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of facilities sold in divestiture agreement | facility			2
Proceeds from sale of business interest			$ 472
Power output of facilities sold | MW			1,269
Dighton and Milford, Massachusetts Facilities | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of properties sold | facility		2
Proceeds from sale of PPE		$ 125
Loss on sale of assets, net							90
Goodwill, written off related to sale of business unit							$ 18
Lee Facility | Disposal Group, Disposed of by Sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from sale of PPE	$ 176
Lee Facility | Disposal Group, Held-for-sale, Not Discontinued Operations
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loss on sale of assets, net					5
Impairment of assets held-for-sale					15
Goodwill, discontinued operation					$ 9

Risk Management Activities, D63

Risk Management Activities, Derivatives and Financial Instruments - Textual (Details)	12 Months Ended
	Dec. 31, 2017USD ($)
Commodity Contracts
Derivative [Line Items]
Credit risk derivative liabilities at fair value	$ 32,000,000
Derivative liability, fair value of collateral	$ 0
Minimum
Derivative [Line Items]
Rolling time period over which the entity can sell energy and capacity through near-term contractual arrangements	1 year
Maximum
Derivative [Line Items]
Rolling time period over which the entity can sell energy and capacity through near-term contractual arrangements	3 years

Risk Management Activities, D64

Risk Management Activities, Derivatives and Financial Instruments - Schedule of Derivative Contracts and Interest Rate Swaps (Details) t in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MMBTUMWhtshares	May 31, 2017USD ($)	Dec. 31, 2016USD ($)
Derivative [Line Items]
Number of Dynegy securities called by each warrant (in shares) | shares	1
Interest Rate Swaps
Derivative [Line Items]
Quantity, purchases (sales), monetary		$ 1,200
Not Designated as Hedging Instrument
Derivative [Line Items]
Right to reclaim cash, offset	$ 47		$ 54
Not Designated as Hedging Instrument | Physical Heat Rate Derivatives
Derivative [Line Items]
Asset (Liability) Fair Value	(95)
Not Designated as Hedging Instrument | Heat Rate Option
Derivative [Line Items]
Asset (Liability) Fair Value	$ (4)
Short | Not Designated as Hedging Instrument | Electric Energy
Derivative [Line Items]
Quantity, purchases (sales), energy | MWh	62
Asset (Liability) Fair Value	$ (150)
Short | Not Designated as Hedging Instrument | Electricity Basis Derivatives
Derivative [Line Items]
Quantity, purchases (sales), energy | MWh	25
Asset (Liability) Fair Value	$ (4)
Short | Not Designated as Hedging Instrument | Physical Heat Rate Derivatives
Derivative [Line Items]
Quantity, purchases (sales), energy | MWh	17
Short | Not Designated as Hedging Instrument | Heat Rate Option
Derivative [Line Items]
Quantity, purchases (sales), energy | MWh	1
Long | Not Designated as Hedging Instrument | Natural Gas Derivatives
Derivative [Line Items]
Quantity, purchases (sales), energy | MMBTU	404
Asset (Liability) Fair Value	$ (4)
Long | Not Designated as Hedging Instrument | Natural Gas Basis Derivatives
Derivative [Line Items]
Quantity, purchases (sales), energy | MMBTU	120
Asset (Liability) Fair Value	$ (1)
Long | Not Designated as Hedging Instrument | Physical Heat Rate Derivatives
Derivative [Line Items]
Quantity, purchases (sales), energy | MMBTU	177
Long | Not Designated as Hedging Instrument | Heat Rate Option
Derivative [Line Items]
Quantity, purchases (sales), energy | MMBTU	6
Long | Not Designated as Hedging Instrument | Emissions Derivative
Derivative [Line Items]
Quantity, purchases (sales), mass | t	8
Asset (Liability) Fair Value	$ 2
Long | Not Designated as Hedging Instrument | Interest Rate Swaps
Derivative [Line Items]
Quantity, purchases (sales), monetary	1,961
Asset (Liability) Fair Value	$ 7
Long | Not Designated as Hedging Instrument | Common stock warrants
Derivative [Line Items]
Quantity, purchases (sales), equity unit (in shares) | shares	9,000,000
Asset (Liability) Fair Value	$ (2)

Risk Management Activities, D65

Risk Management Activities, Derivatives and Financial Instruments - Schedule of Derivative Instruments in the Balance Sheet (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Assets [Abstract]
Derivative Assets, Gross Fair Value	$ 175	$ 311
Derivative Asset, Contract Netting	(117)	(165)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	58	146
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(426)	(360)
Derivative Liability, Contract Netting	117	165
Right to reclaim cash, offset	47	54
Derivative Liabilities, Net Fair Value	(262)	(141)
Total Derivatives, Gross Fair Value	(251)	(49)
Total Derivatives, Contract Netting	0	0
Total Derivatives, Collateral or Margin Received or Paid	47	54
Total Derivatives, Net Fair Value	(204)	5
Commodity Contracts | Assets from Risk Management Activities
Derivative Assets [Abstract]
Derivative Assets, Gross Fair Value	155	311
Derivative Asset, Contract Netting	(112)	(165)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	43	146
Commodity Contracts | Liabilities from Risk Management Activities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(411)	(329)
Derivative Liability, Contract Netting	112	165
Right to reclaim cash, offset	47	54
Derivative Liabilities, Net Fair Value	(252)	(110)
Interest Rate Contracts | Assets from Risk Management Activities
Derivative Assets [Abstract]
Derivative Assets, Gross Fair Value	20
Derivative Asset, Contract Netting	(5)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0
Derivative Assets, Net Fair Value	15
Interest Rate Contracts | Liabilities from Risk Management Activities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(13)	(30)
Derivative Liability, Contract Netting	5	0
Right to reclaim cash, offset	0	0
Derivative Liabilities, Net Fair Value	(8)	(30)
Common stock warrants | Other long-term liabilities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(2)	(1)
Derivative Liability, Contract Netting	0	0
Right to reclaim cash, offset	0	0
Derivative Liabilities, Net Fair Value	$ (2)	$ (1)

Risk Management Activities, D66

Risk Management Activities, Derivatives and Financial Instruments - Schedule of Collateral Posted and Balance Sheet Location (Details) - Commodity Contracts - Prepayments and other current assets, Collateral posted - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Cash Collateral Posted [Abstract]
Gross collateral posted with counterparties	$ 92	$ 116
Right to reclaim cash, offset	47	54
Net collateral within Prepayments and other current assets	$ 45	$ 62

Risk Management Activities, D67

Risk Management Activities, Derivatives and Financial Instruments - Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commodity Contracts | Revenues
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	$ (58)	$ 270	$ 194
Interest Rate Contracts | Interest Expense
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	16	(5)	(15)
Common stock warrants | Other Income (Expense), Net
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	$ 16	$ 6	$ 54

Fair Value Measurements - Textu

Fair Value Measurements - Textual (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Maximum exposure	$ 7	$ 79
Prepayments and other current assets, Collateral posted
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Posted collateral for derivatives with counterparties	$ 45	$ 62

Fair Value Measurements - Sched

Fair Value Measurements - Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets:
Assets from commodity risk management activities:	$ 155	$ 311
Assets from interest rate contracts	20
Total assets	175
Liabilities:
Liabilities from commodity risk management activities:	(411)	(329)
Liabilities from interest rate contracts	(13)	(30)
Total liabilities	(426)	(360)
Electricity derivatives
Assets:
Assets from commodity risk management activities:	77	138
Liabilities:
Liabilities from commodity risk management activities:	(231)	(257)
Natural gas derivatives
Assets:
Assets from commodity risk management activities:	72	173
Liabilities:
Liabilities from commodity risk management activities:	(77)	(62)
Heat rate derivatives
Assets:
Assets from commodity risk management activities:	4
Liabilities:
Liabilities from commodity risk management activities:	(99)
Heat Rate Option
Liabilities:
Liabilities from commodity risk management activities:	(4)
Emissions derivatives
Assets:
Assets from commodity risk management activities:	2
Liabilities:
Liabilities from commodity risk management activities:		(10)
Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	(2)	(1)
Level 1
Assets:
Assets from commodity risk management activities:	0	0
Assets from interest rate contracts	0
Total assets	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Liabilities from interest rate contracts	0	0
Total liabilities	(2)	(1)
Level 1 | Electricity derivatives
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Heat rate derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0
Level 1 | Heat Rate Option
Liabilities:
Liabilities from commodity risk management activities:	0
Level 1 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:		0
Level 1 | Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	(2)	(1)
Level 2
Assets:
Assets from commodity risk management activities:	139	287
Assets from interest rate contracts	20
Total assets	159
Liabilities:
Liabilities from commodity risk management activities:	(370)	(307)
Liabilities from interest rate contracts	(13)	(30)
Total liabilities	(383)	(337)
Level 2 | Electricity derivatives
Assets:
Assets from commodity risk management activities:	71	118
Liabilities:
Liabilities from commodity risk management activities:	(200)	(245)
Level 2 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	62	169
Liabilities:
Liabilities from commodity risk management activities:	(71)	(52)
Level 2 | Heat rate derivatives
Assets:
Assets from commodity risk management activities:	4
Liabilities:
Liabilities from commodity risk management activities:	(99)
Level 2 | Heat Rate Option
Liabilities:
Liabilities from commodity risk management activities:	0
Level 2 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	2
Liabilities:
Liabilities from commodity risk management activities:		(10)
Level 2 | Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 3
Assets:
Assets from commodity risk management activities:	16	24
Assets from interest rate contracts	0
Total assets	16
Liabilities:
Liabilities from commodity risk management activities:	(41)	(22)
Liabilities from interest rate contracts	0	0
Total liabilities	(41)	(22)
Level 3 | Electricity derivatives
Assets:
Assets from commodity risk management activities:	6	20
Liabilities:
Liabilities from commodity risk management activities:	(31)	(12)
Level 3 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	10	4
Liabilities:
Liabilities from commodity risk management activities:	(6)	(10)
Level 3 | Heat rate derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0
Level 3 | Heat Rate Option
Liabilities:
Liabilities from commodity risk management activities:	(4)
Level 3 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:		0
Level 3 | Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	$ 0	$ 0

Fair Value Measurements - Sensi

Fair Value Measurements - Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations (Details) - Market Approach Valuation Technique - Level 3 - Recurring MWh in Millions, BTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)MWhBTU$ / MWh$ / MMBTU
Power Forward Contracts
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Purchase (sales), quantity | MWh	14
Net Fair Value | $	$ (23)
Financial Transmission Rights
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Purchase (sales), quantity | MWh	22
Net Fair Value | $	$ (2)
Physical Heat Rate Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Net Fair Value | $	0
Heat Rate Option
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Net Fair Value | $	$ (4)
Natural Gas Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Purchase (sales), quantity | BTU	95
Net Fair Value | $	$ 4
Minimum | Power Forward Contracts
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread (usd per mwh)	4.25
Minimum | Financial Transmission Rights
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu)	0
Minimum | Physical Heat Rate Derivative - MMBtu
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu) | $ / MMBTU	2
Minimum | Physical Heat Rate Derivative - MWh
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu)	22
Price correlation	70.00%
Minimum | Heat Rate Option
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Price volatility	30.00%
Minimum | Natural Gas Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu) | $ / MMBTU	2
Maximum | Power Forward Contracts
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread (usd per mwh)	6.25
Maximum | Financial Transmission Rights
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu)	6
Maximum | Physical Heat Rate Derivative - MMBtu
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu) | $ / MMBTU	2.80
Maximum | Physical Heat Rate Derivative - MWh
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu)	27
Price correlation	100.00%
Maximum | Heat Rate Option
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Price volatility	50.00%
Maximum | Natural Gas Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price (usd per mwh and usd per mmbtu) | $ / MMBTU	2.45
Long | Physical Heat Rate Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity, purchases (sales), energy | BTU	4
Long | Heat Rate Option
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity, purchases (sales), energy | BTU	6
Short | Physical Heat Rate Derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity, purchases (sales), energy | MWh	0
Short | Heat Rate Option
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity, purchases (sales), energy | MWh	(1)

Fair Value Measurements - Sch71

Fair Value Measurements - Schedule of Changes in Fair Value of Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Unrealized gains (losses) relating to instruments held	$ (207)	$ 148	$ 130
Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	2	(48)	(4)
Total gains included in earnings	(25)	104	42
Settlements	1	(54)	36
Option premiums received	(4)
Acquired derivatives	1		(122)
Ending balance	(25)	2	(48)
Unrealized gains (losses) relating to instruments held	(25)	104	42
Level 3 | Electricity derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	8	(18)	(4)
Total gains included in earnings	(30)	59	39
Settlements	(4)	(33)	1
Option premiums received	0
Acquired derivatives	1		(54)
Ending balance	(25)	8	(18)
Unrealized gains (losses) relating to instruments held	(30)	59	39
Level 3 | Natural Gas Derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	(6)	(32)	0
Total gains included in earnings	5	49	3
Settlements	5	(23)	28
Option premiums received	0
Acquired derivatives	0		(63)
Ending balance	4	(6)	(32)
Unrealized gains (losses) relating to instruments held	5	49	3
Level 3 | Heat rate derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	0	0	0
Total gains included in earnings	0		0
Settlements	0		9
Option premiums received	(4)
Acquired derivatives	0		(9)
Ending balance	(4)	0	0
Unrealized gains (losses) relating to instruments held	0		0
Level 3 | Coal derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 0	2	0
Total gains included in earnings		(4)	0
Settlements		2	(2)
Acquired derivatives			4
Ending balance		0	2
Unrealized gains (losses) relating to instruments held		$ (4)	$ 0

Fair Value Measurements - Sch72

Fair Value Measurements - Schedule of Fair Value of Receivables and Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Carrying Amount | Dynegy, Inc | Term Loan, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	$ (1,944)		$ (2,213)
Carrying Amount | Dynegy, Inc | Revolving Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	0		0
Carrying Amount | Dynegy, Inc | 6.75% Senior Notes, due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(845)		(2,083)
Carrying Amount | Dynegy, Inc | 7.375% Senior Notes, due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(1,734)		(1,731)
Carrying Amount | Dynegy, Inc | 5.875% Senior Notes, due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(493)		(492)
Carrying Amount | Dynegy, Inc | 7.625% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(1,237)		(1,237)
Carrying Amount | Dynegy, Inc | 8.034% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(188)		0
Carrying Amount | Dynegy, Inc | 8.00% Senior Notes, due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(739)		(738)
Carrying Amount | Dynegy, Inc | 8.125% Senior Notes, due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(842)		0
Carrying Amount | Dynegy, Inc | 7.00% Amortizing Notes, due 2019 (TEUs)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(51)		(78)
Carrying Amount | Dynegy, Inc | Forward Capacity Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(215)		(205)
Carrying Amount | Dynegy, Inc | Inventory Financing Agreements
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(48)		(129)
Carrying Amount | Dynegy, Inc | Equipment Financing Agreements
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(97)		(73)
Carrying Amount | Genco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	0		(825)
Fair Value | Dynegy, Inc | Term Loan, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(2,021)		(2,250)
Fair Value | Dynegy, Inc | Revolving Facility
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	0		0
Fair Value | Dynegy, Inc | 6.75% Senior Notes, due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(873)		(2,137)
Fair Value | Dynegy, Inc | 7.375% Senior Notes, due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(1,844)		(1,665)
Fair Value | Dynegy, Inc | 5.875% Senior Notes, due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(508)		(431)
Fair Value | Dynegy, Inc | 7.625% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(1,344)		(1,156)
Fair Value | Dynegy, Inc | 8.034% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(198)		0
Fair Value | Dynegy, Inc | 8.00% Senior Notes, due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(812)		(703)
Fair Value | Dynegy, Inc | 8.125% Senior Notes, due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(933)		0
Fair Value | Dynegy, Inc | 7.00% Amortizing Notes, due 2019 (TEUs)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(54)		(90)
Fair Value | Dynegy, Inc | Forward Capacity Agreement
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(215)		(205)
Fair Value | Dynegy, Inc | Inventory Financing Agreements
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(48)		(127)
Fair Value | Dynegy, Inc | Equipment Financing Agreements
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	(97)		(73)
Fair Value | Genco
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt, gross	$ 0		$ (366)
Unsecured Obligations | 6.75% Senior Notes, due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	6.75%
Unsecured Obligations | 7.375% Senior Notes, due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.375%
Unsecured Obligations | 5.875% Senior Notes, due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	5.875%
Unsecured Obligations | 7.625% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.625%
Unsecured Obligations | 8.034% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	8.034%
Unsecured Obligations | 8.00% Senior Notes, due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	8.00%
Unsecured Obligations | 8.125% Senior Notes, due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	8.125%
Unsecured Obligations | 7.00% Amortizing Notes, due 2019 (TEUs)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.00%
Unsecured Obligations | Dynegy, Inc | 6.75% Senior Notes, due 2019
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	6.75%
Unsecured Obligations | Dynegy, Inc | 7.375% Senior Notes, due 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.375%
Unsecured Obligations | Dynegy, Inc | 5.875% Senior Notes, due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	5.875%
Unsecured Obligations | Dynegy, Inc | 7.625% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.625%
Unsecured Obligations | Dynegy, Inc | 8.034% Senior Notes, due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage		8.034%
Unsecured Obligations | Dynegy, Inc | 8.00% Senior Notes, due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	8.00%
Unsecured Obligations | Dynegy, Inc | 8.125% Senior Notes, due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	8.125%
Unsecured Obligations | Dynegy, Inc | 7.00% Amortizing Notes, due 2019 (TEUs)
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Interest rate, stated percentage	7.00%

Cash Flow Information - Disclos

Cash Flow Information - Disclosure of Cash Flow and Non-cash Investing and Financing Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Interest paid (net of amount capitalized of $2, $10, and $12, respectively)	$ 555	$ 548	$ 491
Taxes paid (net of refunds)	(5)	(1)	2
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	7	(13)	(8)
Change in capital expenditures pursuant to equipment financing agreements	24	11	63
Issuance of 2017 Warrants	17	0	0
Issuance of senior notes related to the Genco restructuring	188	0	0
Sale of interest in Conesville facility	(58)	0	0
Acquisition of interest in Zimmer facility	27	0	0
Non-cash consideration transferred for acquisitions	0	0	105
Interest amount capitalized	$ 2	$ 10	$ 12

Inventory - Summary of invento

Inventory - Summary of inventories (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Materials and supplies	$ 242	$ 182
Coal	166	238
Fuel oil	15	17
Natural gas	9	0
Emissions allowances	13	8
Total	445	445
Inventory impairment	$ 14	$ 0	$ 0

Property, Plant and Equipment

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 11,068	$ 8,579
Accumulated depreciation	(2,184)	(1,458)
Property, plant and equipment, net	8,884	7,121
Power generation
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	9,998	7,537
Buildings and improvements
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	955	944
Office and other equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 115	$ 98

Property, Plant and Equipment76

Property, Plant and Equipment - Total interest costs incurred and interest capitalized for construction in progress (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Total interest costs incurred	$ 576	$ 556	$ 487
Capitalized interest	$ 2	$ 10	$ 12

Property, Plant and Equipment -

Property, Plant and Equipment - Impairments (Details) - USD ($) $ in Millions	3 Months Ended						12 Months Ended
	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
PPE impairments	$ 29	$ 99	$ 20	$ 1	$ 212	$ 645	$ 119	$ 849	$ 99
Inventory fair value							0
Inventory impairment							14	0	0
Equity investment fair value							173
Equity investment impairment							0	9	0
Assets held-for-sale fair value							176
Assets held-for-sale, goodwill							9
Assets held-for-sale impairment							15	0	0
Total Impairments							148	858	99
Brayton Point
Property, Plant and Equipment [Line Items]
Severance costs							12
Baldwin
Property, Plant and Equipment [Line Items]
PPE fair value							97
PPE impairments							0	645	0
Stuart
Property, Plant and Equipment [Line Items]
PPE fair value							0
PPE impairments							0	56	0
Newton FGD
Property, Plant and Equipment [Line Items]
PPE fair value							0
PPE impairments							0	148	0
Killen
Property, Plant and Equipment [Line Items]
PPE fair value							0
PPE impairments							20	0	0
Hennepin
Property, Plant and Equipment [Line Items]
PPE fair value							16
PPE impairments							10	0	0
Havana
Property, Plant and Equipment [Line Items]
PPE fair value							37
PPE impairments							89	0	0
Wood River
Property, Plant and Equipment [Line Items]
PPE fair value							0
PPE impairments							0	0	74
Brayton Point
Property, Plant and Equipment [Line Items]
PPE fair value							86
PPE impairments							$ 0	$ 0	$ 25

Joint Ownership of Generating78

Joint Ownership of Generating Facilities - Ownership Interest in Jointly Owned Facilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 08, 2017	May 09, 2017	Dec. 31, 2016
Schedule of Equity Method Investments [Line Items]
Property, Plant and Equipment	$ 11,068			$ 8,579
Accumulated Depreciation	(2,184)			(1,458)
Property, plant and equipment, net	$ 8,884			$ 7,121
Miami Fort
Schedule of Equity Method Investments [Line Items]
Ownership Interest	100.00%	36.00%		64.00%
Property, Plant and Equipment				$ 207
Accumulated Depreciation				(39)
Construction Work in Progress				4
Property, plant and equipment, net				$ 172
Stuart
Schedule of Equity Method Investments [Line Items]
Ownership Interest	39.00%			39.00%
Property, Plant and Equipment	$ 1			$ 0
Accumulated Depreciation	0			0
Construction Work in Progress	0			4
Property, plant and equipment, net	$ 1			$ 4
Conesville
Schedule of Equity Method Investments [Line Items]
Ownership Interest			40.00%	40.00%
Property, Plant and Equipment				$ 61
Accumulated Depreciation				(3)
Construction Work in Progress				6
Property, plant and equipment, net				$ 64
Zimmer
Schedule of Equity Method Investments [Line Items]
Ownership Interest	100.00%	28.10%		46.50%
Property, Plant and Equipment				$ 115
Accumulated Depreciation				(25)
Construction Work in Progress				6
Property, plant and equipment, net				$ 96
Killen
Schedule of Equity Method Investments [Line Items]
Ownership Interest	33.00%			33.00%
Property, Plant and Equipment	$ 0			$ 19
Accumulated Depreciation	0			(2)
Construction Work in Progress	0			3
Property, plant and equipment, net	$ 0			$ 20

Joint Ownership of Generating79

Joint Ownership of Generating Facilities - Additional Information (Details) - USD ($) $ in Millions	Dec. 08, 2017	May 09, 2017	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Fair value of assets acquired						$ 27	$ 0	$ 0
Increase (decrease) in inventories						(110)	(154)	119
Loss on sale of assets, net			$ (15)	$ (78)	$ (29)	122	1	1
Carrying value of sold asset						58	$ 0	$ 0
Conesville
Schedule of Equity Method Investments [Line Items]
Ownership Interest		40.00%					40.00%
Loss on sale of assets, net						31
Carrying value of sold asset						$ 58
Zimmer
Schedule of Equity Method Investments [Line Items]
Ownership Interest	28.10%		100.00%			100.00%	46.50%
Percentage ownership after all transactions		71.90%
Fair value of assets acquired						$ 27
Property, plant and equipment, additions		$ 14
Increase (decrease) in inventories		14
Liabilities incurred		$ 1
Zimmer | American Electric Power
Schedule of Equity Method Investments [Line Items]
Ownership Interest		25.40%
Letters of credit outstanding		$ 58
Miami Fort
Schedule of Equity Method Investments [Line Items]
Ownership Interest	36.00%		100.00%			100.00%	64.00%
Zimmer and Miami Fort
Schedule of Equity Method Investments [Line Items]
Payments to acquire interest in joint venture	$ 70

Unconsolidated Investments (Det

Unconsolidated Investments (Details) - USD ($) $ in Millions	Nov. 21, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 07, 2017
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliate		$ 123	$ 0
Earnings from unconsolidated investments		8	7	$ 1
Distributions from unconsolidated investments		5	1	3
Distributions from unconsolidated investments		12	14	8
Other than temporary impairment		0	9	0
Northeast Energy LP
Schedule of Equity Method Investments [Line Items]
Percent of voting interests acquired					50.00%
Assets acquired and liabilities assumed, net					$ 39
Earnings from unconsolidated investments		8
Distributions from unconsolidated investments		17
Distributions from unconsolidated investments		$ 12
Elwood Energy LLC and Elwood Expansion LLC
Schedule of Equity Method Investments [Line Items]
Earnings from unconsolidated investments			7	1
Distributions from unconsolidated investments			15	11
Distributions from unconsolidated investments			14	$ 8
Percent divested	50.00%
Proceeds from sale of equity method investments	$ 173
Other than temporary impairment			$ 9

Intangible Assets and Liabili81

Intangible Assets and Liabilities - Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	1 Months Ended
	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016
Intangible Assets:
Gross Carrying Amount		$ 208	$ 273
Accumulated Amortization		(144)	(212)
Net Carrying Amount		64	61
Intangible Liabilities:
Gross Carrying Amount		(119)	(204)
Accumulated Amortization		71	149
Net Carrying Amount		(48)	(55)
Gross Carrying Amount		89	69
Accumulated Amortization		(73)	(63)
Net Carrying Amount		16	6
Engie Acquisition
Intangible Assets:
Gross Carrying Amount	$ 50
Intangible Liabilities:
Gross Carrying Amount	(30)
Gross Carrying Amount	$ 20
Intangible asset, useful life	41 months
Intangible liability, useful life	33 months
Electricity contracts
Intangible Liabilities:
Gross Carrying Amount		(11)	(28)
Accumulated Amortization		7	26
Net Carrying Amount		(4)	(2)
Electricity contracts | Engie Acquisition
Intangible Liabilities:
Gross Carrying Amount	$ (11)
Intangible liability, useful life	32 months
Gas contracts | Engie Acquisition
Intangible Liabilities:
Gross Carrying Amount	$ 0
Intangible liability, useful life	1 month
Coal contracts
Intangible Liabilities:
Gross Carrying Amount		0	(49)
Accumulated Amortization		0	42
Net Carrying Amount		0	(7)
Coal transport contracts
Intangible Liabilities:
Gross Carrying Amount		(48)	(86)
Accumulated Amortization		44	73
Net Carrying Amount		(4)	(13)
Gas transport contracts
Intangible Liabilities:
Gross Carrying Amount		(58)	(41)
Accumulated Amortization		19	8
Net Carrying Amount		(39)	(33)
Gas transport contracts | Engie Acquisition
Intangible Liabilities:
Gross Carrying Amount	$ (17)
Intangible liability, useful life	35 months
Gas storage contracts
Intangible Liabilities:
Gross Carrying Amount		(2)	0
Accumulated Amortization		1	0
Net Carrying Amount		(1)	0
Gas storage contracts | Engie Acquisition
Intangible Liabilities:
Gross Carrying Amount	$ (2)
Intangible liability, useful life	13 months
Electricity contracts
Intangible Assets:
Gross Carrying Amount		178	260
Accumulated Amortization		(131)	(206)
Net Carrying Amount		47	54
Electricity contracts | Engie Acquisition
Intangible Assets:
Gross Carrying Amount	$ 34
Intangible Liabilities:
Intangible asset, useful life	39 months
Gas transport contracts
Intangible Assets:
Gross Carrying Amount		30	13
Accumulated Amortization		(13)	(6)
Net Carrying Amount		$ 17	$ 7
Gas transport contracts | Engie Acquisition
Intangible Assets:
Gross Carrying Amount	$ 16
Intangible Liabilities:
Intangible asset, useful life	47 months

Intangible Assets and Liabili82

Intangible Assets and Liabilities - Amortization of Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	$ 12	$ 21	$ (11)
Electricity contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	32	70	75
Coal contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	(5)	(41)	(60)
Coal transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	(9)	(27)	(32)
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	(5)	19	6
Gas storage contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	$ (1)	$ 0	$ 0

Intangible Assets and Liabili83

Intangible Assets and Liabilities - Amortization Expense for the Next Five Years of Finite Lived Intangible Assets (Details) $ in Millions	Dec. 31, 2017USD ($)
Intangible Assets, Net (Excluding Goodwill) [Abstract]
2,018	$ 11
2,019	17
2,020	2
2,021	(3)
2,022	$ (4)

Tangible Equity Units (Details)

Tangible Equity Units (Details) - TEUs $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / shares	Jun. 21, 2016$ / sharesshares
Tangible Equity Units [Line Items]
Number of units issued (in units) | shares		4.6
Interest rate, stated percentage	7.00%	7.00%
Unit price (in dollars per unit)	$ 100	$ 100
Net proceeds | $	$ 443
Issuance costs | $	$ 17
Initial principal amount per unit (in dollars per unit)	$ 18.95
Volume-weighted average price, period	20 days
Minimum
Tangible Equity Units [Line Items]
Settlement rate per unit	5.0201
Maximum
Tangible Equity Units [Line Items]
Settlement rate per unit	6.1996
Secondary annual installments
Tangible Equity Units [Line Items]
Quarterly cash installment (in dollars per unit)	$ 1.75
Initial Installment, due October 1, 2016
Tangible Equity Units [Line Items]
Quarterly cash installment (in dollars per unit)	$ 1.94

Tangible Equity Units (Net Proc

Tangible Equity Units (Net Proceeds Schedule) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Jun. 21, 2016
TEUs
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 100	$ 100
Gross proceeds	$ 460
Less: Issuance costs	(17)
Net proceeds	$ 443
SPC
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 81.0509
Gross proceeds	$ 373
Less: Issuance costs	(14)
Net proceeds	$ 359
Amortizing Note
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 18.9491
Gross proceeds	$ 87
Less: Issuance costs	(3)
Net proceeds	$ 84

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Aug. 21, 2017	Jul. 07, 2017	Jul. 06, 2017	Mar. 29, 2017	Mar. 28, 2017	Feb. 02, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Long-term debt	$ 8,630							$ 9,099
Unamortized debt discounts and issuance costs	(197)							(120)
Total debt	8,433							8,979
Less: Current maturities, including unamortized discounts, net	105							201
Total Long-term debt	8,328							8,778
Forward Capacity Agreement
Debt Instrument [Line Items]
Long-term debt	241		$ 110	$ 99	$ 121	$ 110
Equipment Financing Agreements
Debt Instrument [Line Items]
Total debt	97
Secured Obligations:
Debt Instrument [Line Items]
Long-term debt	2,307							2,572
Secured Obligations: | Term Loan, due 2024
Debt Instrument [Line Items]
Long-term debt	2,018							2,224
Secured Obligations: | Revolving Facility
Debt Instrument [Line Items]
Long-term debt	0							0
Secured Obligations: | Forward Capacity Agreement
Debt Instrument [Line Items]
Long-term debt	241							219
Secured Obligations: | Inventory Financing Agreements
Debt Instrument [Line Items]
Long-term debt	48							129
Unsecured Obligations:
Debt Instrument [Line Items]
Long-term debt	$ 6,323							6,527
Unsecured Obligations: | 7.00% Amortizing Notes, due 2019 (TEUs)
Debt Instrument [Line Items]
Interest rate, stated percentage	7.00%
Long-term debt	$ 53							80
Unsecured Obligations: | 6.75% Senior Notes, due 2019
Debt Instrument [Line Items]
Interest rate, stated percentage	6.75%
Long-term debt	$ 850							2,100
Unsecured Obligations: | 7.375% Senior Notes, due 2022
Debt Instrument [Line Items]
Interest rate, stated percentage	7.375%
Long-term debt	$ 1,750							1,750
Unsecured Obligations: | 5.875% Senior Notes, due 2023
Debt Instrument [Line Items]
Interest rate, stated percentage	5.875%
Long-term debt	$ 500							500
Unsecured Obligations: | 7.625% Senior Notes, due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	7.625%
Long-term debt	$ 1,250							1,250
Unsecured Obligations: | 8.034% Senior Notes, due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage	8.034%
Long-term debt	$ 188						$ 188	0
Unsecured Obligations: | 8.00% Senior Notes, due 2025
Debt Instrument [Line Items]
Interest rate, stated percentage	8.00%
Long-term debt	$ 750							750
Unsecured Obligations: | 8.125% Senior Notes, due 2026
Debt Instrument [Line Items]
Interest rate, stated percentage	8.125%
Long-term debt	$ 850	$ 850						0
Unsecured Obligations: | Equipment Financing Agreements
Debt Instrument [Line Items]
Long-term debt	$ 132							$ 97

Debt - Maturities of Long Term

Debt - Maturities of Long Term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Disclosure [Abstract]
2,018	$ 115
2,019	971
2,020	136
2,021	59
2,022	1,760
Thereafter	5,589
Total	$ 8,630	$ 9,099

Debt - Textual (Details)

Debt - Textual (Details)	Dec. 20, 2017USD ($)	Dec. 19, 2017	Aug. 22, 2017USD ($)	Aug. 21, 2017USD ($)	Oct. 14, 2016	Feb. 28, 2017USD ($)	Dec. 31, 2017USD ($)	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Jul. 07, 2017USD ($)	Jul. 06, 2017USD ($)	May 31, 2017USD ($)	Mar. 29, 2017USD ($)	Mar. 28, 2017USD ($)	Feb. 02, 2017USD ($)	Jun. 21, 2016	Aug. 31, 2015USD ($)agreement	Apr. 01, 2015USD ($)
Debt Instrument [Line Items]
Loss on early extinguishment of debt									$ 79,000,000	$ 0	$ 0
Consolidated senior secured net debt to consolidated adjusted EBITDA ratio									4
Long-term debt							$ 8,630,000,000		$ 8,630,000,000	9,099,000,000
Long-term debt							8,433,000,000		8,433,000,000	8,979,000,000
RGGI Repurchase Agreement
Debt Instrument [Line Items]
Number of repurchase agreements | agreement																			2
Assets sold under agreements to repurchase, carrying amount							$ 48,000,000		$ 48,000,000										$ 78,000,000
Assets repurchased under agreement to repurchase						$ 30,000,000
Assets sold under agreements to repurchase, carry rate							3.49%		3.49%
Amortizing Note
Debt Instrument [Line Items]
Proceeds from issuance of tangible equity units, gross										$ 87,000,000
TEUs
Debt Instrument [Line Items]
Interest rate, stated percentage										7.00%								7.00%
Proceeds from issuance of tangible equity units, gross										$ 460,000,000
Affiliated Entity | Restructuring Support Agreement | Genco And Ad Hock Group Of Shareholders
Debt Instrument [Line Items]
Term of warrants					7 years
Senior Notes
Debt Instrument [Line Items]
Borrowed money maximum, percent of total assets							30.00%		30.00%
Unsecured Obligations
Debt Instrument [Line Items]
Long-term debt							$ 6,323,000,000		$ 6,323,000,000	6,527,000,000
Interest Rate Swaps
Debt Instrument [Line Items]
Derivative, notional amount														$ 1,200,000,000
Derivative, average fixed interest rate (as a percentage)														1.97%
Revolving Facility
Debt Instrument [Line Items]
Extinguishment of debt, amount							300,000,000
Term Facilities and Revolving Facility, (The Credit Agreement)
Debt Instrument [Line Items]
Maximum borrowing capacity							3,563,000,000		3,563,000,000
Term Loan, due 2024
Debt Instrument [Line Items]
Maximum borrowing capacity							2,018,000,000		$ 2,018,000,000
Debt instrument term									7 years
Interest rate decrease									0.75%
Loss on early extinguishment of debt	$ 6,000,000							$ 7,000,000	$ 8,000,000
Write off of debt issuance costs	4,000,000							5,000,000	6,000,000
Write-off of unamortized debt discount	1,000,000							2,000,000	2,000,000
Extinguishment of debt, amount			$ 200,000,000
Debt extinguishment fees	$ 1,000,000
Term Loan, due 2024 | Base Rate
Debt Instrument [Line Items]
Basis spread on variable rate (as a percentage)	1.75%	2.25%
Term Loan, due 2024 | Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percentage)	1.50%	2.25%
Term Loan, due 2024 | LIBOR
Debt Instrument [Line Items]
Basis spread on variable rate (as a percentage)	2.75%	3.25%
Term Loan, due 2024 | LIBOR | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percentage)	2.50%	2.75%
Revolving Facility
Debt Instrument [Line Items]
Maximum borrowing capacity							1,545,000,000		1,545,000,000
Line of credit facility, amount outstanding							0		0
Letters of credit outstanding							353,000,000		353,000,000
Revolving Credit Facility, Tranche B
Debt Instrument [Line Items]
Line of credit facility, amount outstanding							120,000,000		120,000,000
Revolver Tranche due 2021 | Revolving Facility
Debt Instrument [Line Items]
Maximum borrowing capacity							450,000,000		450,000,000
Term Facilities Tranche B-2 | Interest Rate Swaps
Debt Instrument [Line Items]
Derivative, notional amount								$ 761,000,000
Derivative, average fixed interest rate (as a percentage)								3.03%
8.034% Senior Notes, due 2024 | Unsecured Obligations
Debt Instrument [Line Items]
Long-term debt							$ 188,000,000		$ 188,000,000	0							$ 188,000,000
Interest rate, stated percentage							8.034%		8.034%
8.125% Senior Notes, due 2026 | Unsecured Obligations
Debt Instrument [Line Items]
Long-term debt				$ 850,000,000			$ 850,000,000		$ 850,000,000	0
Interest rate, stated percentage							8.125%		8.125%
6.75% Senior Notes, due 2019 | Unsecured Obligations
Debt Instrument [Line Items]
Loss on early extinguishment of debt									$ 58,000,000
Write off of debt issuance costs									8,000,000
Extinguishment of debt, amount				$ 1,250,000,000
Debt extinguishment fees									6,000,000
Long-term debt							$ 850,000,000		$ 850,000,000	2,100,000,000
Interest rate, stated percentage							6.75%		6.75%
Write off of premiums									$ 44,000,000
Letter of Credit | Macquarie Bank
Debt Instrument [Line Items]
Maximum borrowing capacity							$ 55,000,000		55,000,000
Letters of credit outstanding							55,000,000		55,000,000
Letter of Credit Reimbursement Agreement | Letter of Credit
Debt Instrument [Line Items]
Maximum borrowing capacity							50,000,000		50,000,000
Letters of credit outstanding							30,000,000		30,000,000
Forward Capacity Agreement
Debt Instrument [Line Items]
Long-term debt							$ 241,000,000		$ 241,000,000			$ 110,000,000	$ 99,000,000		$ 121,000,000	$ 110,000,000
Effective percentage							4.90%		4.90%
Forward Capacity Agreement | Maximum
Debt Instrument [Line Items]
Long-term debt													$ 109,000,000
Inventory Financing Agreements | EquiPower Acquisition
Debt Instrument [Line Items]
Maximum borrowing capacity																				$ 15,000,000
Equipment Financing Agreements
Debt Instrument [Line Items]
Long-term debt							$ 97,000,000		$ 97,000,000
Unamortized discount							35,000,000		35,000,000
Equipment Financing Agreements | Unsecured Obligations
Debt Instrument [Line Items]
Long-term debt							$ 132,000,000		$ 132,000,000	$ 97,000,000

Income Taxes - Narratives (Deta

Income Taxes - Narratives (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Reduction to deferred tax assets		$ 394
Change in ATM, income tax benefit	$ 223
Loss before income taxes		$ 538	$ 1,289	$ 427
Effective tax rate (percent)		(113.00%)	(3.00%)	(111.00%)
Current income tax benefit		$ 18	$ 16
Unrecognized tax benefits that would impact effective tax rate	3	3
Domestic Tax Authority
Income Tax Contingency [Line Items]
Operating loss carryforwards	4,600	4,600
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Operating loss carryforwards	$ 3,600	$ 3,600

Income Taxes - Current and Defe

Income Taxes - Current and Deferred Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Current tax benefit (expense)	$ 233	$ 15	$ (3)
Deferred tax benefit	377	30	477
Income tax benefit	$ 610	$ 45	$ 474

Income Taxes - Reconciliation o

Income Taxes - Reconciliation of Income Tax Benefit (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Investments, Owned, Federal Income Tax Note [Line Items]
Federal statutory income tax rate, percent			35.00%	35.00%	35.00%
Expected tax benefit at U.S. statutory rate			$ 189	$ 451	$ 149
State taxes			35	16	68
Permanent differences			(21)	(4)	16
Non-deductible goodwill			(10)	0	0
Valuation allowance			879	(404)	271
NOL adjustments from use limitations			(13)	(17)	0
Adjustment to AMT credits			(17)	0	(26)
Change in federal tax rate as included in TCJA			(429)	0	0
Other			(3)	3	(4)
Income tax benefit			610	45	474
Permanent differences, change in fair value of warrants expense (benefit)			1	2	18
Engie Acquisition
Investments, Owned, Federal Income Tax Note [Line Items]
Legal fees			22
Deferred tax asset, Reduction of valuation allowance	$ 37	$ 317	354
EquiPower Acquisition
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred tax asset, Reduction of valuation allowance				3	$ 453
Genco
Investments, Owned, Federal Income Tax Note [Line Items]
Permanent differences			$ (8)	$ (5)

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Non-current deferred tax assets:
NOL carryforwards	$ 1,195	$ 1,629
AMT, state, and other tax credit carryforwards	25	241
Reserves (legal, environmental and other)	4	7
Pension and other post-employment benefits	11	18
Asset retirement obligations	68	85
Deferred financing costs and intangible/other contracts	22	48
Derivative contracts	69	57
Other	29	46
Subtotal	1,423	2,131
Less: valuation allowance	(852)	(1,704)	$ (1,276)	$ (1,535)
Total non-current deferred tax assets	571	427
Non-current deferred tax liabilities:
Depreciation and other property differences	(560)	(371)
Derivative contracts	(7)	(44)
Other	(11)	(17)
Total non-current deferred tax liabilities	(578)	(432)
Net deferred tax liability	$ (7)	$ (5)

Income Taxes - Changes in Valua

Income Taxes - Changes in Valuation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 1,704	$ 1,276	$ 1,535
Balance at End of Period	852	1,704	1,276
Charged to Costs and Expenses
Movement in Valuation Allowances and Reserves [Roll Forward]
Changes in valuation allowance—continuing operations:	(854)	428	(259)
Charged to Other Accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Changes in valuation allowance—continuing operations:	$ 2	$ 0	$ 0

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits, beginning of period	$ 3	$ 3	$ 4
Increase due to ENGIE acquisition	63	0	0
Decrease due to rate changes	(26)	0	0
Decrease due to settlements and payments	0	0	(1)
Unrecognized tax benefits, end of period	$ 40	$ 3	$ 3

Stockholders' Equity - Textual

Stockholders' Equity - Textual (Details)	Nov. 01, 2017shares	Feb. 07, 2017USD ($)	Feb. 24, 2016USD ($)shares	Dec. 31, 2017USD ($)Plan$ / sharesshares	Dec. 31, 2016USD ($)$ / sharesshares	Dec. 31, 2015USD ($)$ / shares	Oct. 02, 2017shares	Jun. 21, 2016$ / sharesshares	Oct. 01, 2012$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, shares authorized (in shares)				20,000,000	20,000,000
Preferred stock, par value (in dollars per share) | $ / shares				$ 0.01	$ 0.01
Conversion of convertible securities (in shares)	12,900,000
Payment for contingent consideration liability | $				$ 375,000,000
Common stock, shares authorized (in shares)				420,000,000	420,000,000				420,000,000
Common stock, par value (in dollars per share) | $ / shares				$ 0.01	$ 0.01				$ 0.01
Treasury stock (in shares)				11,326,122
Number of securities called by warrants or rights (in shares)							15,600,000
Warrants to exercise price (in dollars per share) | $ / shares									$ 40
Number of securities called by each warrant (in shares)				1
Authorized shares (in shares)				3,200,000
Expiration period				10 years
Compensation expense | $				$ 44,000,000	$ 31,000,000	$ 28,000,000
Tax benefit from compensation expense | $				15,000,000	11,000,000	10,000,000
Compensation cost not yet recognized | $				$ 31,000,000
Period for recognition				1 year 5 months 6 days
Total fair value of shares vested | $				$ 26,000,000	27,000,000	18,000,000
Cash received from option exercises | $				$ 0	$ 0	500,000
Additional tax deduction from share-based payment awards, less than | $						$ 1,000,000
Grants in period, weighted average exercise price (in dollars per share) | $ / shares				$ 8.02	$ 11.05	$ 27.43
Intrinsic value of options exercised, less than | $					$ 1,000,000	$ 1,000,000
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				2,500,000	1,500,000
Payment for vesting of equity awards | $				$ 3,000,000
Vested in period (in shares)				400,000
Share-based liabilities paid | $				$ 1,000,000
Forfeited (in shares)				100,000
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				3,177,000
Vested in period (in shares)				1,241,000
Forfeited (in shares)				107,000
Grants in period, weighted average fair value (in dollars per share) | $ / shares				$ 7.99	$ 11.20	$ 28.93
Award vesting period				3 years
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted (in shares)				583,000
Vested in period (in shares)				3,000
Forfeited (in shares)				186,000
Grants in period, weighted average fair value (in dollars per share) | $ / shares				$ 8.02	$ 16.48	$ 27.54
Award vesting period				3 years
Minimum performance factor				0.00%
Maximum performance factor				200.00%
Target percent				100.00%
Maximum performance factor				100.00%
A&R 2012 LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of plans | Plan				1
2017 Warrants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Warrants to exercise price (in dollars per share) | $ / shares				$ 35
Class of warrant or right, outstanding (in shares)				9,000,000
Number of securities called by each warrant (in shares)				1
TEUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of units issued (in units)								4,600,000
Interest rate, stated percentage					7.00%			7.00%
Price per TEU (in dollars per unit) | $ / shares					$ 100			$ 100
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payment for contingent consideration liability | $		$ 375,000,000
Preferred Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock offering, including shares sold through underwriter's option (in shares)				4,000,000
Common Stock | Parent | PIPE Stock Purchase Agreement
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock to be issued for acquisitions (in shares)			13,711,152
Stock to be issued, value | $			$ 150,000,000
Affiliated Entity | Restructuring Support Agreement | Genco And Ad Hock Group Of Shareholders | 2017 Warrants
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Class of warrant or right, outstanding (in shares)				9,000,000
Warrant term				7 years

Stockholders' Equity - Common S

Stockholders' Equity - Common Stock Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Common Stock, Shares Outstanding [Roll Forward]
Beginning of period (in shares)	117,300,618
End of period (in shares)	144,384,491	117,300,618
Common Stock
Common Stock, Shares Outstanding [Roll Forward]
Beginning of period (in shares)	117,000,000	117,000,000	124,000,000
Shares repurchases (in treasury) (in shares)	0	0	(11,000,000)
Shares issued from conversion of preferred stock (in shares)	13,000,000	0	0
Share issued under long-term compensation plans (in shares)	0	0	1,000,000
End of period (in shares)	144,000,000	117,000,000	117,000,000
Common Stock | PIPE Stock Purchase Agreement
Common Stock, Shares Outstanding [Roll Forward]
Shares issued as consideration acquisition (in shares)	14,000,000	0	0
Common Stock | ECP Purchase Agreements
Common Stock, Shares Outstanding [Roll Forward]
Shares issued as consideration acquisition (in shares)	0	0	3,000,000

Stockholders' Equity - Stock Op

Stockholders' Equity - Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Options (in thousands)
Outstanding at beginning of period (in shares)	2,805
Granted (in shares)	1,454
Forfeited (in shares)	(10)
Expired (in shares)	(42)
Outstanding at end of period (in shares)	4,207	2,805
Vested and unvested expected to vest (in shares)	4,207
Exercisable at end of period (in shares)	2,023
Weighted Average Exercise Price
Outstanding at beginning of period (in dollars per share)	$ 18.69
Share-based Compensation Arrangements by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price	8.02	$ 11.05	$ 27.43
Forfeited, Weighted Average Exercise Price (in dollars per share)	27.24
Expired, Weighted Average Exercise Price (in dollars per share)	21.79
Outstanding at end of period (in dollars per share)	14.95	$ 18.69
Vested and unvested expected to vest, Weighted Average Exercise Price (in dollars per share)	14.95
Exercisable at end of period, Weighted Average Exercise Price (in dollars per share)	$ 20.02
Weighted Average Remaining Contractual Life, Outstanding at end of period	7 years 7 months 24 days
Weighted Average Remaining Contractual Life, Vested and unvested expected to vest	7 years 7 months 24 days
Weighted Average Remaining Contractual Life, Exercisable at end of period	6 years 4 months 24 days
Aggregate Intrinsic Value - Outstanding at end of period	$ 6.4
Aggregate Intrinsic Value - Vested and unvested expected to vest	6.4
Aggregate Intrinsic Value - Exercisable at end of period	$ 0.5

Stockholders' Equity - Black-Sc

Stockholders' Equity - Black-Scholes Model, Weighted-Average Assumptions for Grants (Details) - $ / shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Dividend Yield	0.00%	0.00%	0.00%
Expected volatility	48.50%	41.19%	27.70%
Risk-free interest rate	2.07%	1.42%	1.64%
Expected option life	5 years 6 months	5 years 6 months	5 years 6 months
Weighted average grant-date fair value of options granted (in dollars per share)	$ 3.71	$ 4.37	$ 7.93

Stockholders' Equity - Activity

Stockholders' Equity - Activity for Restricted and Performance Stock Units (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Restricted stock units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of period (in shares)	2,717
Granted (in shares)	3,177
Vested and released (in shares)	(1,241)
Forfeited (in shares)	(107)
Outstanding at end of period (in shares)	4,546	2,717
Weighted Average Grant Date Fair Value
Weighted Average Grant Date Fair Value, Outstanding at beginning of period (in dollars per share)	$ 16.11
Weighted Average Grant Date Fair Value, Granted (in dollars per share)	7.99	$ 11.20	$ 28.93
Weighted Average Grant Date Fair Value, Vested and released (in dollars per share)	19.04
Weighted Average Grant Date Fair Value, Forfeited (in dollars per share)	11.08
Weighted Average Grant Date Fair Value, Outstanding at end of period (in dollars per share)	$ 9.75	$ 16.11
Performance stock units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Outstanding at beginning of period (in shares)	1,221
Granted (in shares)	583
Vested and released (in shares)	(3)
Forfeited (in shares)	(186)
Outstanding at end of period (in shares)	1,615	1,221
Weighted Average Grant Date Fair Value
Weighted Average Grant Date Fair Value, Outstanding at beginning of period (in dollars per share)	$ 16.48
Weighted Average Grant Date Fair Value, Granted (in dollars per share)	8.02	$ 16.48	$ 27.54
Weighted Average Grant Date Fair Value, Vested and released (in dollars per share)	26.66
Weighted Average Grant Date Fair Value, Forfeited (in dollars per share)	23.10
Weighted Average Grant Date Fair Value, Outstanding at end of period (in dollars per share)	$ 12.65	$ 16.48

Stockholders' Equity - Signific

Stockholders' Equity - Significant Components of Shares Outstanding (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Jun. 21, 2016	Dec. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding at the beginning of the period (in shares)	144,384,491	117,300,618
Weighted-average shares during the period: Shares issuances (in shares)	13,000,000	0	4,000,000
Shares converted from preferred stock (in shares)	2,000,000	0	0
Weighted-average shares during the period: Shares repurchases (in shares)	0	0	(3,000,000)
Prepaid stock purchase contract (TEUs) (in shares)	0	12,000,000	0
Basic weighted-average shares (in shares)	155,000,000	129,000,000	125,000,000
Dilution from potentially dilutive shares (in shares)	7,000,000	0	1,000,000
Diluted weighted-average shares (in shares)	162,000,000	129,000,000	126,000,000
Settlement shares outstanding, included in the computation of basic earnings (loss) per share (in shares)				23,100,000
TEU settlement, additional number of shares (in shares)	5,400,000
TEUs, settlement, maximum (in shares)	28,500,000
Incremental common shares attributable to dilutive effect of share-based payment arrangements (in shares)	1,900,000
Common Stock and Tangible Equity Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares outstanding at the beginning of the period (in shares)		140,000,000	117,000,000		124,000,000

Stockholders' Equity - Anti-dil

Stockholders' Equity - Anti-dilutive shares - potentially dilutive in future (Details) - shares	Nov. 01, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Oct. 02, 2017
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		11,800,000	39,200,000	29,000,000
Preferred stock, dividend rate		5.375%	5.375%
Number of securities called by warrants or rights (in shares)					15,600,000
Conversion of convertible securities (in shares)	12,900,000
2017 Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Class of warrant or right, outstanding (in shares)		9,000,000
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		2,800,000	2,800,000	500,000
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		0	1,300,000	0
Performance stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		0	1,200,000	0
Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		9,000,000	15,600,000	15,600,000
Series A 5.375% mandatory convertible preferred stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		0	12,900,000	12,900,000
Preferred stock, dividend rate		5.375%	5.375%	5.375%
TEUs
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (in shares)		0	5,400,000	0

Stockholders' Equity - AOCI (De

Stockholders' Equity - AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning of period	$ 2,039	$ 2,919	$ 3,023
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)	19	3	4
Actuarial gain and plan amendments, tax	5	3	0
Settlement cost (net of tax of zero)	0	6	0
Settlement cost, tax	0	0	0
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)	(8)	(5)	(4)
Amortization of unrecognized prior service credit and actuarial gain, tax	0	0	0
Other comprehensive income, net of tax	11	4	0
End of period	1,893	2,039	2,919
AOCI
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning of period	21	19	20
Actuarial gain and plan amendments (net of tax of $5, $3, and zero, respectively)	19	2	3
Settlement cost (net of tax of zero)	0	5	0
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)	(8)	(5)	(4)
Other comprehensive income, net of tax	11	2	(1)
End of period	$ 32	$ 21	$ 19

Commitments and Contingencies -

Commitments and Contingencies - Legal Proceedings (Details) $ in Millions	Jan. 04, 2018complaint	Dec. 31, 2014surface_impoundment	Dec. 31, 2017state	Sep. 30, 2016USD ($)	May 31, 2015complaint
Vermillion Facility, Old East and North Sites
Loss Contingencies [Line Items]
Number of localized areas where groundwater standards were exceeded | surface_impoundment		2
Gas Index Pricing Litigation | Pending Litigation
Loss Contingencies [Line Items]
Number of states in which entity operates | state			3
Advatech Dispute | Pending Litigation
Loss Contingencies [Line Items]
Estimate of possible loss | $				$ 81
Contested invoice amount | $				$ 1
Vistra Merger Stockholder Litigation | Subsequent Event
Loss Contingencies [Line Items]
Loss Contingency, New Claims Filed, Number	2
MISO 2015-2016 Planning Resource Auction
Loss Contingencies [Line Items]
Pending number of claims					3
MISO 2015-2016 Planning Resource Auction | Pending Litigation
Loss Contingencies [Line Items]
Pending number of claims					1

Commitments and Contingencie104

Commitments and Contingencies - Other Commitments and Contingencies (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Loss Contingencies [Line Items]
Rental expense	$ 5,000,000	$ 5,000,000	$ 5,000,000
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,018	6,000,000
2,019	5,000,000
2,020	5,000,000
2,021	5,000,000
2,022	4,000,000
Limestone purchase commitments
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted	25,000,000
Alternative Energy Interconnect Systems
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted	17,000,000
Water Services
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted	23,000,000
Other Agreements
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted	23,000,000
Other Indemnities
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Current carrying value	0
Dynegy's CSA Commitment
Loss Contingencies [Line Items]
Estimate of possible loss	$ 707,000,000
Purchase obligation, amount	112,000,000
Spare parts	$ 103,000,000
Gas Purchase Commitments
Loss Contingencies [Line Items]
Minimum purchase obligations	212,000,000
Transportation of Natural Gas
Loss Contingencies [Line Items]
Minimum purchase obligations	183,000,000
Coal
Loss Contingencies [Line Items]
Minimum purchase obligations	802,000,000
Coal Transportation
Loss Contingencies [Line Items]
Minimum purchase obligations	$ 837,000,000

Employee Compensation, Savin105

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Narratives (Details) - USD ($)	3 Months Ended	12 Months Ended			36 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Contributions by employer		$ 63,000,000	$ 43,000,000	$ 50,000,000
Employer matching contribution, percent		100.00%
Maximum annual employee contribution, percent		5.00%
Employers matching contribution, annual vesting percent		50.00%
Employer discretionary contribution					$ 0
Defined contribution plan, cost		$ 13,000,000	15,000,000	10,000,000
Interest crediting rate		4.00%
OCI, defined benefit plan, gain (loss)		$ 15,000,000
Settlement cost		0	6,000,000	0
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligations	$ 501,000,000	527,000,000	501,000,000		$ 527,000,000
Amortization of prior service credit and net actuarial loss (gain)		2,000,000	1,000,000	1,000,000
Prior service credit		$ 2,000,000	1,000,000	1,000,000
Pension Benefits | EEI Other post-employment benefit plan
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year		6.40%
Pension Benefits | DYN Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year		5.60%
Pension Benefits | DYN Pension Plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations		46.00%			46.00%
Pension Benefits | DYN Pension Plan | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations		54.00%			54.00%
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligations	42,000,000	$ 40,000,000	42,000,000		$ 40,000,000
Prior service credit		$ 5,000,000	$ 4,000,000	$ 3,000,000
Other Benefits | Union Employees
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year		7.10%
Other Benefits | Salaried employees
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year		4.50%
Other Benefits | EEI Other post-employment benefit plan
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation, net of tax gain	17,000,000
Settlement cost	$ 6,000,000
Other Benefits | EEI Other post-employment benefit plan | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations		60.00%			60.00%
Other Benefits | EEI Other post-employment benefit plan | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations		40.00%			40.00%

Employee Compensation, Savin106

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of the year	$ 466
Fair value of plan assets, end of the year	480	$ 466
Pension Benefits
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of the year	508	483
Service cost	17	16	$ 14
Interest cost	20	20	18
Actuarial loss	28	23
Benefits paid	(36)	(32)
Plan change	(10)	(2)
Settlements	0	0
Acquisitions	0	0
Divestitures	0	0
Benefit obligation, end of the year	527	508	483
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of the year	415	410
Actual return on plan assets	65	37
Employer contributions	4	0
Benefits paid	(36)	(32)
Settlements	0	0
Acquisitions	0	0
Divestitures	0	0
Transfers Out	0	0
Fair value of plan assets, end of the year	448	415	410
Funded status	(79)	(93)
Other Benefits
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Benefit obligation, beginning of the year	42	74
Service cost	0	1	1
Interest cost	2	3	4
Actuarial loss	1	4
Benefits paid	(4)	(6)
Plan change	(1)	(17)
Settlements	0	(17)
Acquisitions	0	0
Divestitures	0	0
Benefit obligation, end of the year	40	42	74
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of the year	49	67
Actual return on plan assets	4	2
Employer contributions	0	0
Benefits paid	(2)	(3)
Settlements	0	(17)
Acquisitions	0	0
Divestitures	0	0
Transfers Out	(19)	0
Fair value of plan assets, end of the year	32	49	$ 67
Funded status	$ (8)	$ 7

Employee Compensation, Savin107

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Pension and Other Post-Retirement Amounts Recognized on the Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current assets	$ 0	$ 7
Current liabilities	0	0
Non-current liabilities	(79)	(100)
Net amount recognized	(79)	(93)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current assets	33	32
Current liabilities	(2)	(2)
Non-current liabilities	(20)	(23)
Net amount recognized	$ 11	$ 7

Employee Compensation, Savin108

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Pre-tax Amounts Recognized in AOCI (Loss) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Prior service credit	$ (19)	$ (12)
Actuarial loss (gain)	(8)	2
Net gain recognized	(27)	(10)
Prior service credit	(3)
Actuarial gain	0
Net gain recognized	(3)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Prior service credit	(43)	(47)
Actuarial loss (gain)	1	1
Net gain recognized	(42)	$ (46)
Prior service credit	(5)
Actuarial gain	(1)
Net gain recognized	$ (6)

Employee Compensation, Savin109

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 17	$ 16	$ 14
Interest cost	20	20	18
Expected return on plan assets	(25)	(22)	(23)
Prior service credit	(2)	(1)	(1)
Actuarial loss (gain)	0	0	0
Net periodic benefit cost (gain)	10	13	8
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1	1
Interest cost	2	3	4
Expected return on plan assets	(2)	(4)	(4)
Prior service credit	(5)	(4)	(3)
Actuarial loss (gain)	(1)	0	0
Net periodic benefit cost (gain)	(6)	(4)	(2)
Settlement cost	0	6	0
Total benefit cost (gain)	$ (6)	$ 2	$ (2)

Employee Compensation, Savin110

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Weighted Average Assumptions Used in Determining Benefit Obligations and Net Benefit Obligations (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.60%	4.05%
Rate of compensation increase	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	3.60%	4.05%	4.35%
Rate of compensation increase	3.50%	3.50%	3.50%
Pension Benefits | DYN Pension Plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	6.20%	5.60%	5.70%
Pension Benefits | EEI Other post-employment benefit plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	6.40%	5.90%	6.00%
Other Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	3.55%	4.00%
Rate of compensation increase	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	3.55%	4.00%	4.35%
Rate of compensation increase	3.50%	3.50%	3.50%
Other Benefits | EEI Other post-employment benefit plan
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	5.75%	5.40%	5.50%
Other Benefits | EEI Other post-employment benefit plan | Union Employees
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	6.90%	6.30%	6.20%
Other Benefits | EEI Other post-employment benefit plan | Salaried employees
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	4.60%	4.50%	4.80%

Employee Compensation, Savin111

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Retirement Benefits [Abstract]
Health care cost trend rate assumed for next year	7.00%	7.25%	7.00%
Ultimate trend rate	4.50%	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2,025	2,025	2,023

Employee Compensation, Savin112

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - The Impact of a One Percent Increase/Decrease in Assumed Health Care Cost Trend Rates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Retirement Benefits [Abstract]
Aggregate impact on service cost and interest cost, Increase	$ 0
Aggregate impact on service cost and interest cost, Decrease	0
Impact on accumulated post-employment benefit obligation, Increase	3
Impact on accumulated post-employment benefit obligation, Decrease	$ (2)

Employee Compensation, Savin113

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Fair Value Hierarchy of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 480	$ 466
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	94	101
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	386	365
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	7	6
Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	7	4
Cash and cash equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	2
Cash and cash equivalents | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Equity securities | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	150	147
Equity securities | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	20	16
Equity securities | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	71	66
Equity securities | Level 1 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	14	18
Equity securities | Level 1 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	1	1
Equity securities | Level 1 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	9	8
Equity securities | Level 2 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	136	129
Equity securities | Level 2 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	19	15
Equity securities | Level 2 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	62	58
Equity securities | Level 3 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Equity securities | Level 3 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Equity securities | Level 3 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	0	0
Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	232	231
Fixed Income Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	63	70
Fixed Income Funds | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	169	161
Fixed Income Funds | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	$ 0	$ 0

Employee Compensation, Savin114

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Required Contributions (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Employer contributions, past years	$ 4	$ 0
Employee contributions, future years	13
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Employer contributions, past years	2	$ 2
Employee contributions, future years	$ 2

Employee Compensation, Savin115

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Expected Benefit Payments for Future Services for Pension and Other Postretirement Benefits (Details) $ in Millions	Dec. 31, 2017USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 39
2,019	38
2,020	38
2,021	38
2,022	38
2023 - 2027	190
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
2,018	3
2,019	3
2,020	3
2,021	3
2,022	2
2023 - 2027	$ 11

Quarterly Financial Informat116

Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 994	$ 1,437	$ 1,164	$ 1,247	$ 1,107	$ 1,184	$ 904	$ 1,123	$ 4,842	$ 4,318	$ 3,870
Operating income (loss)	(239)	58	(182)	(49)	34	(117)	(702)	145	(412)	(640)	64
Net income (loss)	(95)	(133)	(296)	596	(182)	(249)	(803)	(10)	72	(1,244)	47
Net income (loss) attributable to Dynegy Inc.	$ (95)	$ (137)	$ (302)	$ 592	$ (186)	$ (254)	$ (807)	$ (15)	$ 76	$ (1,240)	$ 50
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (in dollars per share)	$ (0.58)	$ (0.89)	$ (1.96)	$ 4	$ (1.33)	$ (1.81)	$ (6.73)	$ (0.13)	$ 0.37	$ (9.78)	$ 0.22
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (in dollars per share)	$ (0.58)	$ (0.89)	$ (1.96)	$ 3.57	$ (1.33)	$ (1.81)	$ (6.73)	$ (0.13)	$ 0.36	$ (9.78)	$ 0.22
Impairments		$ 29	$ 99	$ 20	$ 1	$ 212	$ 645		$ 119	$ 849	$ 99
Loss on sale of assets, net	$ (15)	(78)	(29)						122	$ 1	$ 1
Gain (loss) on reorganization		$ 12	$ (1)	483
Write-off of deferred financing costs and debt discounts					$ 96
Change in ATM, income tax benefit	223
Engie Acquisition
Condensed Financial Statements, Captions [Line Items]
Deferred tax asset, Reduction of valuation allowance	$ 37			$ 317					$ 354

Condensed Consolidating Fina117

Condensed Consolidating Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 365	$ 1,776	$ 505
Restricted cash	0	62	39
Accounts receivable, net	513	386
Inventory	445	445
Other current assets	201	318
Total Current Assets	1,524	2,987
Property, plant and equipment, net	8,884	7,121
Investment in affiliates	0	0
Investment in unconsolidated affiliate	123	0
Restricted cash	0	2,000	0
Other long-term assets	468	146
Goodwill	772	799
Intercompany note receivable	0	0
Total Assets	11,771	13,053	11,459
Current Liabilities
Accounts payable	367	332
Other current liabilities	682	584
Total Current Liabilities	1,049	916
Liabilities subject to compromise	0	832
Debt, long-term portion, net	8,328	8,778
Intercompany note payable	0	0
Other long-term liabilities	501	488
Total Liabilities	9,878	11,014
Stockholders’ Equity
Dynegy Stockholders’ Equity	1,901	2,042
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	1,901	2,042
Noncontrolling interest	(8)	(3)
Total Equity	1,893	2,039	$ 2,919	$ 3,023
Total Liabilities and Equity	11,771	13,053
Eliminations
Current Assets
Cash and cash equivalents	0	0
Restricted cash		0
Accounts receivable, net	(3,896)	(2,398)
Inventory	0	0
Other current assets	(97)	(104)
Total Current Assets	(3,993)	(2,502)
Property, plant and equipment, net	0	0
Investment in affiliates	(16,132)	(12,175)
Investment in unconsolidated affiliate	0
Restricted cash		0
Other long-term assets	0	0
Goodwill	0	0
Intercompany note receivable	(46)	(8)
Total Assets	(20,171)	(14,685)
Current Liabilities
Accounts payable	(3,891)	(2,398)
Other current liabilities	(102)	(104)
Total Current Liabilities	(3,993)	(2,502)
Liabilities subject to compromise		0
Debt, long-term portion, net	0	0
Intercompany note payable	(3,088)	(3,042)
Other long-term liabilities	0	(8)
Total Liabilities	(7,081)	(5,552)
Stockholders’ Equity
Dynegy Stockholders’ Equity	(16,132)	(12,175)
Intercompany note receivable	3,042	3,042
Total Dynegy Stockholders’ Equity	(13,090)	(9,133)
Noncontrolling interest	0	0
Total Equity	(13,090)	(9,133)
Total Liabilities and Equity	(20,171)	(14,685)
Parent | Reportable Legal Entities
Current Assets
Cash and cash equivalents	233	1,529
Restricted cash		21
Accounts receivable, net	126	141
Inventory	0	0
Other current assets	8	12
Total Current Assets	367	1,703
Property, plant and equipment, net	0	0
Investment in affiliates	16,132	12,175
Investment in unconsolidated affiliate	0
Restricted cash		2,000
Other long-term assets	244	2
Goodwill	0	0
Intercompany note receivable	46	0
Total Assets	16,789	15,880
Current Liabilities
Accounts payable	3,555	1,990
Other current liabilities	156	143
Total Current Liabilities	3,711	2,133
Liabilities subject to compromise		0
Debt, long-term portion, net	8,045	8,531
Intercompany note payable	3,042	3,042
Other long-term liabilities	90	132
Total Liabilities	14,888	13,838
Stockholders’ Equity
Dynegy Stockholders’ Equity	1,901	2,042
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	1,901	2,042
Noncontrolling interest	0	0
Total Equity	1,901	2,042
Total Liabilities and Equity	16,789	15,880
Guarantor Subsidiaries | Reportable Legal Entities
Current Assets
Cash and cash equivalents	124	221
Restricted cash		41
Accounts receivable, net	4,269	2,604
Inventory	415	326
Other current assets	288	408
Total Current Assets	5,096	3,600
Property, plant and equipment, net	8,585	6,772
Investment in affiliates	0	0
Investment in unconsolidated affiliate	123
Restricted cash		0
Other long-term assets	185	109
Goodwill	772	799
Intercompany note receivable	0	8
Total Assets	14,761	11,288
Current Liabilities
Accounts payable	471	443
Other current liabilities	520	377
Total Current Liabilities	991	820
Liabilities subject to compromise		832
Debt, long-term portion, net	256	216
Intercompany note payable	46	0
Other long-term liabilities	367	313
Total Liabilities	1,660	2,181
Stockholders’ Equity
Dynegy Stockholders’ Equity	16,151	12,152
Intercompany note receivable	(3,042)	(3,042)
Total Dynegy Stockholders’ Equity	13,109	9,110
Noncontrolling interest	(8)	(3)
Total Equity	13,101	9,107
Total Liabilities and Equity	14,761	11,288
Non-Guarantor Subsidiaries | Reportable Legal Entities
Current Assets
Cash and cash equivalents	8	26
Restricted cash		0
Accounts receivable, net	14	39
Inventory	30	119
Other current assets	2	2
Total Current Assets	54	186
Property, plant and equipment, net	299	349
Investment in affiliates	0	0
Investment in unconsolidated affiliate	0
Restricted cash		0
Other long-term assets	39	35
Goodwill	0	0
Intercompany note receivable	0	0
Total Assets	392	570
Current Liabilities
Accounts payable	232	297
Other current liabilities	108	168
Total Current Liabilities	340	465
Liabilities subject to compromise		0
Debt, long-term portion, net	27	31
Intercompany note payable	0	0
Other long-term liabilities	44	51
Total Liabilities	411	547
Stockholders’ Equity
Dynegy Stockholders’ Equity	(19)	23
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	(19)	23
Noncontrolling interest	0	0
Total Equity	(19)	23
Total Liabilities and Equity	$ 392	$ 570

Condensed Consolidating Fina118

Condensed Consolidating Financial Information - Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 994	$ 1,437	$ 1,164	$ 1,247	$ 1,107	$ 1,184	$ 904	$ 1,123	$ 4,842	$ 4,318	$ 3,870
Cost of sales, excluding depreciation expense									(2,932)	(2,281)	(2,028)
Gross margin									1,910	2,037	1,842
Operating and maintenance expense									(995)	(940)	(839)
Depreciation expense									(811)	(689)	(587)
Impairments									(148)	(858)	(99)
Loss on sale of assets, net	15	78	29						(122)	(1)	(1)
General and administrative expense									(189)	(161)	(128)
Acquisition and integration costs									(57)	(11)	(124)
Other									0	(17)	0
Operating income (loss)	(239)	58	(182)	(49)	34	(117)	(702)	145	(412)	(640)	64
Bankruptcy reorganization items									494	(96)	0
Earnings from unconsolidated investments									8	7	1
Equity in losses from investments in affiliates									0	0	0
Interest expense									(616)	(625)	(546)
Loss on early extinguishment of debt (Note 13)									(79)	0	0
Other income and expense, net									67	65	54
Loss before income taxes									(538)	(1,289)	(427)
Income tax benefit (Note 14)									610	45	474
Net income (loss)	(95)	(133)	(296)	596	(182)	(249)	(803)	(10)	72	(1,244)	47
Less: Net loss attributable to noncontrolling interest									(4)	(4)	(3)
Net Income attributable to Dynegy Inc.	$ (95)	$ (137)	$ (302)	$ 592	$ (186)	$ (254)	$ (807)	$ (15)	76	(1,240)	50
Eliminations
Condensed Financial Statements, Captions [Line Items]
Revenues									(137)	(92)	(163)
Cost of sales, excluding depreciation expense									137	92	163
Gross margin									0	0	0
Operating and maintenance expense									0	0	0
Depreciation expense									0	0	0
Impairments									0	0	0
Loss on sale of assets, net									0	0	0
General and administrative expense									0	0	0
Acquisition and integration costs									0	0	0
Other										0
Operating income (loss)									0	0	0
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									0	0	0
Equity in losses from investments in affiliates									(824)	715	(476)
Interest expense									14	5	2
Loss on early extinguishment of debt (Note 13)									0
Other income and expense, net									(14)	(5)	(2)
Loss before income taxes									(824)	715	(476)
Income tax benefit (Note 14)									0	0	0
Net income (loss)									(824)	715	(476)
Less: Net loss attributable to noncontrolling interest									0	0	0
Net Income attributable to Dynegy Inc.									(824)	715	(476)
Parent | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Revenues									0	0	0
Cost of sales, excluding depreciation expense									0	0	0
Gross margin									0	0	0
Operating and maintenance expense									0	0	0
Depreciation expense									0	0	0
Impairments									0	0	0
Loss on sale of assets, net									0	(2)	0
General and administrative expense									(28)	(7)	(6)
Acquisition and integration costs									(54)	(10)	0
Other										0
Operating income (loss)									(82)	(19)	(6)
Bankruptcy reorganization items									(18)	0
Earnings from unconsolidated investments									0	0	0
Equity in losses from investments in affiliates									824	(715)	476
Interest expense									(597)	(538)	(475)
Loss on early extinguishment of debt (Note 13)									(79)
Other income and expense, net									28	32	55
Loss before income taxes									76	(1,240)	50
Income tax benefit (Note 14)									0	0	0
Net income (loss)									76	(1,240)	50
Less: Net loss attributable to noncontrolling interest									0	0	0
Net Income attributable to Dynegy Inc.									76	(1,240)	50
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Revenues									4,557	3,942	3,508
Cost of sales, excluding depreciation expense									(2,790)	(2,112)	(1,874)
Gross margin									1,767	1,830	1,634
Operating and maintenance expense									(881)	(796)	(717)
Depreciation expense									(757)	(612)	(505)
Impairments									(148)	(858)	(74)
Loss on sale of assets, net									(123)	1	(1)
General and administrative expense									(155)	(148)	(116)
Acquisition and integration costs									(3)	(1)	(124)
Other										(9)
Operating income (loss)									(300)	(593)	97
Bankruptcy reorganization items									512	(96)
Earnings from unconsolidated investments									8	7	1
Equity in losses from investments in affiliates									0	0	0
Interest expense									(20)	(83)	(69)
Loss on early extinguishment of debt (Note 13)									0
Other income and expense, net									53	38	1
Loss before income taxes									253	(727)	30
Income tax benefit (Note 14)									610	45	472
Net income (loss)									863	(682)	502
Less: Net loss attributable to noncontrolling interest									(4)	(4)	(3)
Net Income attributable to Dynegy Inc.									867	(678)	505
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Revenues									422	468	525
Cost of sales, excluding depreciation expense									(279)	(261)	(317)
Gross margin									143	207	208
Operating and maintenance expense									(114)	(144)	(122)
Depreciation expense									(54)	(77)	(82)
Impairments									0	0	(25)
Loss on sale of assets, net									1	0	0
General and administrative expense									(6)	(6)	(6)
Acquisition and integration costs									0	0	0
Other										(8)
Operating income (loss)									(30)	(28)	(27)
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									0	0	0
Equity in losses from investments in affiliates									0	0	0
Interest expense									(13)	(9)	(4)
Loss on early extinguishment of debt (Note 13)									0
Other income and expense, net									0	0	0
Loss before income taxes									(43)	(37)	(31)
Income tax benefit (Note 14)									0	0	2
Net income (loss)									(43)	(37)	(29)
Less: Net loss attributable to noncontrolling interest									0	0	0
Net Income attributable to Dynegy Inc.									$ (43)	$ (37)	$ (29)

Condensed Consolidating Fina119

Condensed Consolidating Financial Information - Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (95)	$ (133)	$ (296)	$ 596	$ (182)	$ (249)	$ (803)	$ (10)	$ 72	$ (1,244)	$ 47
Actuarial gain (loss) and plan amendments, net of tax									19	3	4
Settlement cost									0	6	0
Amortization of unrecognized prior service credit, net of tax of zero									(8)	(5)	(4)
Other comprehensive loss from investment in affiliates									0	0	0
Other comprehensive income, net of tax									11	4	0
Comprehensive income (loss)									83	(1,240)	47
Less: Comprehensive loss attributable to noncontrolling interest									(4)	(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.									87	(1,238)	49
Reclassification of settlement cost included in net loss, tax									0	0	0
Amortization of unrecognized prior service credit and actuarial gain, tax									0	0	0
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									(824)	715	(476)
Actuarial gain (loss) and plan amendments, net of tax									0	0	0
Settlement cost										0
Amortization of unrecognized prior service credit, net of tax of zero									0	0	0
Other comprehensive loss from investment in affiliates									4	(12)	(11)
Other comprehensive income, net of tax									4	(12)	(11)
Comprehensive income (loss)									(820)	703	(487)
Less: Comprehensive loss attributable to noncontrolling interest									0	(2)	(1)
Total comprehensive income (loss) attributable to Dynegy Inc.									(820)	705	(486)
Parent
Condensed Financial Statements, Captions [Line Items]
Actuarial gain (loss) and plan amendments, net of tax									22
Amortization of unrecognized prior service credit, net of tax of zero									(7)
Other comprehensive loss from investment in affiliates									(4)
Other comprehensive income, net of tax									11
Comprehensive income (loss)									87
Less: Comprehensive loss attributable to noncontrolling interest									0
Total comprehensive income (loss) attributable to Dynegy Inc.									87
Net gain and plan amendments, tax									5	3	0
Amortization of unrecognized prior service credit and actuarial gain, tax									0	0	0
Parent | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									76	(1,240)	50
Actuarial gain (loss) and plan amendments, net of tax										(4)	(8)
Settlement cost										0
Amortization of unrecognized prior service credit, net of tax of zero										(4)	(3)
Other comprehensive loss from investment in affiliates										12	11
Other comprehensive income, net of tax										4	0
Comprehensive income (loss)										(1,236)	50
Less: Comprehensive loss attributable to noncontrolling interest										2	1
Total comprehensive income (loss) attributable to Dynegy Inc.										(1,238)	49
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Actuarial gain (loss) and plan amendments, net of tax									(3)
Amortization of unrecognized prior service credit, net of tax of zero									0
Other comprehensive loss from investment in affiliates									0
Other comprehensive income, net of tax									(3)
Comprehensive income (loss)									860
Less: Comprehensive loss attributable to noncontrolling interest									(4)
Total comprehensive income (loss) attributable to Dynegy Inc.									864
Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									863	(682)	502
Actuarial gain (loss) and plan amendments, net of tax										1	7
Settlement cost										0
Amortization of unrecognized prior service credit, net of tax of zero										0	0
Other comprehensive loss from investment in affiliates										0	0
Other comprehensive income, net of tax										1	7
Comprehensive income (loss)										(681)	509
Less: Comprehensive loss attributable to noncontrolling interest										(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.										(679)	511
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Actuarial gain (loss) and plan amendments, net of tax									0
Amortization of unrecognized prior service credit, net of tax of zero									(1)
Other comprehensive loss from investment in affiliates									0
Other comprehensive income, net of tax									(1)
Comprehensive income (loss)									(44)
Less: Comprehensive loss attributable to noncontrolling interest									0
Total comprehensive income (loss) attributable to Dynegy Inc.									(44)
Non-Guarantor Subsidiaries | Reportable Legal Entities
Condensed Financial Statements, Captions [Line Items]
Net income (loss)									$ (43)	(37)	(29)
Actuarial gain (loss) and plan amendments, net of tax										6	5
Settlement cost										6
Amortization of unrecognized prior service credit, net of tax of zero										(1)	(1)
Other comprehensive loss from investment in affiliates										0	0
Other comprehensive income, net of tax										11	4
Comprehensive income (loss)										(26)	(25)
Less: Comprehensive loss attributable to noncontrolling interest										0	0
Total comprehensive income (loss) attributable to Dynegy Inc.										$ (26)	$ (25)

Condensed Consolidating Fina120

Condensed Consolidating Financial Information - Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 585	$ 645	$ 94
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(224)	(293)	(301)
Acquisitions, net of cash acquired	(3,319)	0	(6,078)
Distributions from unconsolidated investments	12	14	8
Proceeds from asset sales, net	772	176	0
Net intercompany transfers	0	0	0
Other investing	0	10	3
Net cash used in investing activities	(2,759)	(93)	(6,368)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,743	3,014	66
Repayments of borrowings	(2,589)	(589)	(31)
Proceeds from issuance of equity, net of issuance costs	150	359	(6)
Payments of debt extinguishment costs	(50)	0	0
Preferred stock dividends paid	(22)	(22)	(23)
Interest rate swap settlement payments	(20)	(17)	(17)
Repurchase of common stock	0	0	(250)
Acquisition of noncontrolling interest	(375)
Payments related to bankruptcy settlement	(133)
Net intercompany transfers	0	0	0
Intercompany borrowings, net of repayments	0
Other financing	(3)	(3)	(4)
Net cash provided by (used in) financing activities	(1,299)	2,742	(265)
Net increase (decrease) in cash and cash equivalents	(3,473)	3,294	(6,539)
Cash, cash equivalents and restricted cash, beginning of period	3,838	544	7,083
Cash, cash equivalents and restricted cash, end of period	365	3,838	544
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	0	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Acquisitions, net of cash acquired	0		0
Distributions from unconsolidated investments	0	0	0
Proceeds from asset sales, net	0	0
Net intercompany transfers	(691)	(958)	(450)
Other investing		0	0
Net cash used in investing activities	(691)	(958)	(450)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	0	0	0
Repayments of borrowings	0	0	0
Proceeds from issuance of equity, net of issuance costs	0	0	0
Payments of debt extinguishment costs	0
Preferred stock dividends paid	0	0	0
Interest rate swap settlement payments	0	0	0
Repurchase of common stock			0
Acquisition of noncontrolling interest	0
Payments related to bankruptcy settlement	0
Net intercompany transfers	691	958	450
Intercompany borrowings, net of repayments	0
Other financing	0	0	0
Net cash provided by (used in) financing activities	691	958	450
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash, cash equivalents and restricted cash, beginning of period	0	0	0
Cash, cash equivalents and restricted cash, end of period	0	0	0
Parent | Reportable Legal Entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	(427)	(476)	(432)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	0	0	0
Acquisitions, net of cash acquired	(3,244)		(6,207)
Distributions from unconsolidated investments	0	0	0
Proceeds from asset sales, net	775	171
Net intercompany transfers	691	958	450
Other investing		0	0
Net cash used in investing activities	(1,778)	1,129	(5,757)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,743	2,816	(31)
Repayments of borrowings	(2,487)	(563)	(8)
Proceeds from issuance of equity, net of issuance costs	150	359	(6)
Payments of debt extinguishment costs	(50)
Preferred stock dividends paid	(22)	(22)	(23)
Interest rate swap settlement payments	(20)	(17)	(17)
Repurchase of common stock			(250)
Acquisition of noncontrolling interest	(375)
Payments related to bankruptcy settlement	(128)
Net intercompany transfers	0	0	0
Intercompany borrowings, net of repayments	80
Other financing	(3)	(3)	(4)
Net cash provided by (used in) financing activities	(1,112)	2,570	(339)
Net increase (decrease) in cash and cash equivalents	(3,317)	3,223	(6,528)
Cash, cash equivalents and restricted cash, beginning of period	3,550	327	6,855
Cash, cash equivalents and restricted cash, end of period	233	3,550	327
Guarantor Subsidiaries | Reportable Legal Entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	899	1,090	682
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(208)	(243)	(290)
Acquisitions, net of cash acquired	(75)		29
Distributions from unconsolidated investments	12	14	8
Proceeds from asset sales, net	(4)	5
Net intercompany transfers	0	0	0
Other investing		10	3
Net cash used in investing activities	(275)	(214)	(250)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	0	198	78
Repayments of borrowings	(46)	(15)	(23)
Proceeds from issuance of equity, net of issuance costs	0	0	0
Payments of debt extinguishment costs	0
Preferred stock dividends paid	0	0	0
Interest rate swap settlement payments	0	0	0
Repurchase of common stock			0
Acquisition of noncontrolling interest	0
Payments related to bankruptcy settlement	(5)
Net intercompany transfers	(631)	(991)	(347)
Intercompany borrowings, net of repayments	(80)
Other financing	0	0	0
Net cash provided by (used in) financing activities	(762)	(808)	(292)
Net increase (decrease) in cash and cash equivalents	(138)	68	140
Cash, cash equivalents and restricted cash, beginning of period	262	194	54
Cash, cash equivalents and restricted cash, end of period	124	262	194
Non-Guarantor Subsidiaries | Reportable Legal Entities
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	113	31	(156)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(16)	(50)	(11)
Acquisitions, net of cash acquired	0		100
Distributions from unconsolidated investments	0	0	0
Proceeds from asset sales, net	1	0
Net intercompany transfers	0	0	0
Other investing		0	0
Net cash used in investing activities	(15)	(50)	89
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	0	0	19
Repayments of borrowings	(56)	(11)	0
Proceeds from issuance of equity, net of issuance costs	0	0	0
Payments of debt extinguishment costs	0
Preferred stock dividends paid	0	0	0
Interest rate swap settlement payments	0	0	0
Repurchase of common stock			0
Acquisition of noncontrolling interest	0
Payments related to bankruptcy settlement	0
Net intercompany transfers	(60)	33	(103)
Intercompany borrowings, net of repayments	0
Other financing	0	0	0
Net cash provided by (used in) financing activities	(116)	22	(84)
Net increase (decrease) in cash and cash equivalents	(18)	3	(151)
Cash, cash equivalents and restricted cash, beginning of period	26	23	174
Cash, cash equivalents and restricted cash, end of period	$ 8	$ 26	$ 23

Genco Chapter 11 Bankruptcy - N

Genco Chapter 11 Bankruptcy - Narrative (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Feb. 02, 2017	Jan. 25, 2017	Oct. 14, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Oct. 01, 2012
Debt Instrument [Line Items]
Debtor-in-possession facility financing costs						$ 10
Write-off of deferred financing costs and debt discounts				$ 96
Accrued interest				7		7
Long-term debt				9,099	$ 8,630	9,099
Warrants to exercise price (in dollars per share)							$ 40
2017 Warrants
Debt Instrument [Line Items]
Class of warrant or right, outstanding (in shares)					9
Warrants to exercise price (in dollars per share)					$ 35
Unsecured Obligations:
Debt Instrument [Line Items]
Long-term debt				6,527	$ 6,323	6,527
Unsecured Obligations: | 8.034% Senior Notes, due 2024
Debt Instrument [Line Items]
Long-term debt	$ 188			$ 0	$ 188	$ 0
Affiliated Entity | Genco And Ad Hock Group Of Shareholders | Restructuring Support Agreement
Debt Instrument [Line Items]
Payments of debt restructuring costs	122
Term of warrants			7 years
Warrants and rights outstanding	$ 17
Affiliated Entity | Genco And Ad Hock Group Of Shareholders | Restructuring Support Agreement | 2017 Warrants
Debt Instrument [Line Items]
Class of warrant or right, outstanding (in shares)					9
Warrant term					7 years
Affiliated Entity | Genco And Ad Hock Group Of Shareholders | Restructuring Support Agreement | Senior Notes
Debt Instrument [Line Items]
Write-off of senior notes, amount		$ 825

Genco Chapter 11 Bankruptcy - S

Genco Chapter 11 Bankruptcy - Summary of Liabilities Subject to Compromise (Details) $ in Millions	Dec. 31, 2016USD ($)
Debt Instrument [Line Items]
Accrued interest	$ 7
Debt and Accrued Interest	832
7.00% Senior Notes Series H, due 2018
Debt Instrument [Line Items]
Liabilities Subject To Compromise Debt	300
6.30% Senior Notes Series I, due 2020
Debt Instrument [Line Items]
Liabilities Subject To Compromise Debt	250
7.95% Senior Notes Series F, due 2032
Debt Instrument [Line Items]
Liabilities Subject To Compromise Debt	$ 275

Genco Chapter 11 Bankruptcy 123

Genco Chapter 11 Bankruptcy - Schedule of Reorganization Items (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Reorganizations [Abstract]
Liabilities subject to compromise, which were terminated	$ 832
Seven-year unsecured notes	188
Cash consideration	122
2017 Warrants, at fair value	17
Legal and consulting fees	11
Bankruptcy reorganization items	$ (494)	$ 96	$ 0

Segment Information - Reportabl

Segment Information - Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Information
Unaffiliated revenues									$ 4,842	$ 4,290	$ 3,870
Intercompany revenues									0	28	0
Total revenues	$ 994	$ 1,437	$ 1,164	$ 1,247	$ 1,107	$ 1,184	$ 904	$ 1,123	4,842	4,318	3,870
Depreciation expense									(811)	(689)	(587)
Impairments									(148)	(858)	(99)
Loss on sale of assets, net									(122)	(1)	(1)
General and administrative expense									(189)	(161)	(128)
Acquisition and integration costs									(57)	(11)	(124)
Operating income (loss)	(239)	58	(182)	(49)	34	(117)	(702)	145	(412)	(640)	64
Bankruptcy reorganization items									494	(96)	0
Earnings from unconsolidated investments									8	7	1
Interest expense									(616)	(625)	(546)
Loss on early extinguishment of debt (Note 13)									(79)	0	0
Other items, net									67	65	54
Loss before income taxes									(538)	(1,289)	(427)
Income tax benefit									610	45	474
Net income (loss)	(95)	(133)	(296)	596	(182)	(249)	(803)	(10)	72	(1,244)	47
Less: Net loss attributable to noncontrolling interest									(4)	(4)	(3)
Net income (loss) attributable to Dynegy Inc.	(95)	$ (137)	$ (302)	$ 592	(186)	$ (254)	$ (807)	$ (15)	76	(1,240)	50
Identifiable assets (domestic)	11,771				13,053				11,771	13,053	11,459
Investment in unconsolidated affiliate	123								123		190
Capital expenditures									(224)	(293)	(301)
Intersegment Eliminations
Segment Information
Unaffiliated revenues									0	0	0
Intercompany revenues									0	0	0
Total revenues									0	0	0
Depreciation expense									(7)	(5)	(4)
Impairments									0	0	0
Loss on sale of assets, net									0	(2)	0
General and administrative expense									(189)	(161)	(128)
Acquisition and integration costs									(57)	(19)	(124)
Operating income (loss)									(255)	(188)	(252)
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									0	0	0
Interest expense									(616)	(625)	(546)
Loss on early extinguishment of debt (Note 13)									(79)
Other items, net									25	28	55
Income tax benefit									610	45	474
Identifiable assets (domestic)	655				3,795				655	3,795	486
Investment in unconsolidated affiliate	0								0		0
Capital expenditures									(7)	(10)	(13)
PJM | Operating Segments
Segment Information
Unaffiliated revenues									2,352	2,147	1,708
Intercompany revenues									(90)	55	8
Total revenues									2,262	2,202	1,716
Depreciation expense									(379)	(346)	(281)
Impairments									(49)	(65)	0
Loss on sale of assets, net									(36)	0	0
General and administrative expense									0	0	0
Acquisition and integration costs									0	0	0
Operating income (loss)									192	414	423
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									3	7	1
Interest expense									0	0	0
Loss on early extinguishment of debt (Note 13)									0
Other items, net									16	9	(2)
Income tax benefit									0	0	0
Identifiable assets (domestic)	4,912				4,939				4,912	4,939	5,474
Investment in unconsolidated affiliate	67								67		190
Capital expenditures									(103)	(160)	(106)
NY/NE | Operating Segments
Segment Information
Unaffiliated revenues									1,031	836	705
Intercompany revenues									(2)	1	(10)
Total revenues									1,029	837	695
Depreciation expense									(224)	(215)	(186)
Impairments									0	0	(25)
Loss on sale of assets, net									(90)	0	0
General and administrative expense									0	0	0
Acquisition and integration costs									0	0	0
Operating income (loss)									(113)	(29)	(56)
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									5	0	0
Interest expense									0	0	0
Loss on early extinguishment of debt (Note 13)									0
Other items, net									0	1	0
Income tax benefit									0	0	0
Identifiable assets (domestic)	3,374				2,769				3,374	2,769	2,970
Investment in unconsolidated affiliate	56								56		0
Capital expenditures									(50)	(64)	(52)
ERCOT | Operating Segments
Segment Information
Unaffiliated revenues									276
Intercompany revenues									1
Total revenues									277
Depreciation expense									(73)
Impairments									0
Loss on sale of assets, net									0
General and administrative expense									0
Acquisition and integration costs									0
Operating income (loss)									(147)
Bankruptcy reorganization items									0
Earnings from unconsolidated investments									0
Interest expense									0
Loss on early extinguishment of debt (Note 13)									0
Other items, net									0
Income tax benefit									0
Identifiable assets (domestic)	1,563								1,563
Investment in unconsolidated affiliate	0								0
Capital expenditures									(26)
MISO | Operating Segments
Segment Information
Unaffiliated revenues									1,061	1,165	1,279
Intercompany revenues									91	(28)	2
Total revenues									1,152	1,137	1,281
Depreciation expense									(75)	(81)	(68)
Impairments									(99)	(793)	(74)
Loss on sale of assets, net									1	1	0
General and administrative expense									0	0	0
Acquisition and integration costs									0	8	0
Operating income (loss)									(44)	(832)	(43)
Bankruptcy reorganization items									494	(96)
Earnings from unconsolidated investments									0	0	0
Interest expense									0	0	0
Loss on early extinguishment of debt (Note 13)									0
Other items, net									26	15	1
Income tax benefit									0	0	0
Identifiable assets (domestic)	812				1,065				812	1,065	1,995
Investment in unconsolidated affiliate	0								0		0
Capital expenditures									(26)	(52)	(119)
CAISO | Operating Segments
Segment Information
Unaffiliated revenues									122	142	178
Intercompany revenues									0	0	0
Total revenues									122	142	178
Depreciation expense									(53)	(42)	(48)
Impairments									0	0	0
Loss on sale of assets, net									3	0	(1)
General and administrative expense									0	0	0
Acquisition and integration costs									0	0	0
Operating income (loss)									(45)	(5)	(8)
Bankruptcy reorganization items									0	0
Earnings from unconsolidated investments									0	0	0
Interest expense									0	0	0
Loss on early extinguishment of debt (Note 13)									0
Other items, net									0	12	0
Income tax benefit									0	0	0
Identifiable assets (domestic)	455				$ 485				455	485	534
Investment in unconsolidated affiliate	$ 0								0		0
Capital expenditures									$ (12)	$ (7)	$ (11)

Segment Information - Revenue b

Segment Information - Revenue by Major Customers (Details) - Sales Revenue, Segment - Customer Concentration Risk - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
PJM | PMJ and MISO
Revenue, Major Customer [Line Items]
Revenues	$ 1,313	$ 1,366	$ 1,088
MISO | MISO
Revenue, Major Customer [Line Items]
Revenues	506	688	$ 842
ISO-NE | MISO and NY/NE
Revenue, Major Customer [Line Items]
Revenues	$ 669	$ 437

Segment Information - Narrative

Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2017segment
Concentration Risk [Line Items]
Number of reportable segments	5
Workforce Subject to Collective Bargaining Arrangement | Unionized Employees Concentration Risk
Concentration Risk [Line Items]
Concentration risk, percentage	40.00%