Dyne Therapeutics 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Feb. 08, 2016	Jun. 30, 2015
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, 2015
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			$ 3,478,775,830
Entity Common Stock, Shares Outstanding		116,903,586
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents		$ 505	$ 1,870
Restricted cash		39	113
Accounts receivable, net of allowance for doubtful accounts of $1 and $2, respectively		402	270
Inventory		597	208
Assets from risk management activities		100	78
Intangible assets		102	27
Prepayments and other current assets		200	108
Total Current Assets		1,945	2,674
Property, Plant and Equipment		9,235	3,685
Accumulated depreciation		(888)	(430)
Property, Plant and Equipment, Net		8,347	3,255
Other Assets
Investment in unconsolidated affiliate		190	0
Restricted cash		0	5,100
Assets from risk management activities		18	2
Goodwill		797	0
Intangible assets		62	38
Deferred income taxes		0	20
Other long-term assets		180	143
Total Assets		11,539	11,232
Current Liabilities
Accounts payable		292	216
Accrued interest		74	80
Deferred income taxes		0	20
Intangible liabilities		85	45
Accrued liabilities and other current liabilities		175	157
Liabilities from risk management activities		103	132
Debt, current portion		83	31
Total Current Liabilities		812	681
Debt, long-term portion		7,206	7,075
Other Liabilities
Liabilities from risk management activities		105	31
Asset retirement obligations		230	205
Deferred income taxes		29	0
Intangible liabilities		55	36
Other long-term liabilities		183	181
Total Liabilities		$ 8,620	$ 8,209
Commitments and Contingencies (Note 16)
Stockholders’ Equity
Preferred Stock, $0.01 par value, 20,000,000 authorized; Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding at December 31, 2015 and December 31, 2014, Respectively		$ 400	$ 400
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,228,477 shares issued and 116,902,355 shares outstanding at December 31, 2015; 124,436,941 shares issued and outstanding at December 31, 2014		1	1
Additional paid-in capital		3,187	3,338
Accumulated other comprehensive income, net of tax	[1]	19	20
Accumulated deficit		(686)	(736)
Total Dynegy Stockholders’ Equity		2,921	3,023
Noncontrolling interest		(2)	0
Total Equity		2,919	3,023
Total Liabilities and Equity		$ 11,539	$ 11,232
[1]	Includes a tax impact of $31 million due to remeasurements of certain of our pension and other post-employment benefit plans in 2013 that will only reverse if and when the Dynegy plans terminate.

CONSOLIDATED BALANCE SHEETS (PA

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Accounts receivable, allowance for doubtful accounts	$ 1	$ 2
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, series A 5.375%	5.375%	5.375%
Preferred stock, shares authorized	20,000,000	20,000,000
Preferred stock, shares issued	4,000,000	4,000,000
Preferred stock, shares outstanding	4,000,000	4,000,000
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized	420,000,000	420,000,000
Common stock, shares issued	128,228,477	124,436,941
Common stock, shares outstanding	116,902,355	124,436,941

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Revenues		$ 3,870	$ 2,497	$ 1,466
Cost of sales, excluding depreciation expense		(2,028)	(1,661)	(1,145)
Gross margin		1,842	836	321
Operating and maintenance expense		(839)	(477)	(308)
Depreciation expense		(587)	(247)	(216)
Impairments		(99)	0	0
Gain (loss) on sale of assets, net		(1)	18	2
General and administrative expense		(128)	(114)	(97)
Acquisition and integration costs		(124)	(35)	(20)
Operating income (loss)		64	(19)	(318)
Bankruptcy reorganization items, net		0	3	(1)
Earnings from unconsolidated investments		1	10	2
Interest expense		(546)	(223)	(97)
Loss on extinguishment of debt		0	0	(11)
Other income and expense, net		54	(39)	8
Loss before income taxes		(427)	(268)	(417)
Income tax benefit (Note 14)		474	1	58
Income (loss) from continuing operations		47	(267)	(359)
Income from discontinued operations, net of tax (Note 21)		0	0	3
Net income (loss)		47	(267)	(356)
Less: Net income (loss) attributable to noncontrolling interest		(3)	6	0
Net income (loss) attributable to Dynegy Inc.		50	(273)	(356)
Less: Dividends on preferred stock		22	5	0
Net income (loss) attributable to Dynegy Inc. common stockholders		$ 28	$ (278)	$ (356)
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders:
Income (loss) from continuing operations (in dollars per share)	[1]	$ 0.22	$ (2.65)	$ (3.59)
Income from discontinued operationsIncome (loss) from continuing operations (in dollars per share)		0	0	0.03
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholdersIncome (loss) from continuing operations (in dollars per share)		$ 0.22	$ (2.65)	$ (3.56)
Basic shares outstanding (shares)		125	105	100
Diluted shares outstanding (shares)		126	105	100
[1]	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2014 and 2013.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income (loss)		$ (134)	$ (24)	$ 386	$ (181)	$ (103)	$ (5)	$ (122)	$ (37)	$ 47	$ (267)	$ (356)
Actuarial gain (loss) and plan amendments (net of tax expense of zero, zero, and $31, respectively)										4	(36)	57
Amounts reclassified from accumulated other comprehensive income:
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)	[1]									0	0	(7)
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)	[2]									(4)	(5)	(2)
Other comprehensive income (loss), net of tax										0	(41)	48
Comprehensive income (loss)										47	(308)	(308)
Less: Comprehensive income (loss) attributable to noncontrolling interest										(2)	3	1
Total comprehensive income (loss) attributable to Dynegy Inc.										$ 49	$ (311)	$ (309)
[1]	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (PARENTHETICAL) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Actuarial gain (loss) and plan amendments, tax		$ 2	$ 0	$ 31
Reclassification of curtailment gain included in net loss, tax	[1]	0	0	0
Amortization of unrecognized prior service cost (credit) and actuarial loss (gain), tax	[2]	$ 0	$ 0	$ 0
[1]	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ 47	$ (267)	$ (356)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation expense	587	247	216
Loss on extinguishment of debt	0	0	11
Non-cash interest expense	38	21	2
Amortization of intangibles	(11)	45	251
Impairment	99	0	0
Risk management activities	130	(26)	(38)
(Gain) loss on sale of assets, net	1	(18)	(2)
Earnings from unconsolidated investments	1	0	0
Deferred income taxes	(477)	(1)	(56)
Change in value of common stock warrants	(54)	40	1
Other	51	35	14
Changes in working capital:
Accounts receivable, net	(64)	161	(75)
Inventory	(119)	(20)	24
Prepayments and other current assets	84	22	48
Accounts payable and accrued liabilities	90	(131)	71
Distributions from unconsolidated investments	3	0	0
Changes in restricted cash	(28)	0	0
Changes in non-current assets	(27)	(4)	(12)
Changes in non-current liabilities	5	7	0
Net cash provided by operating activities	94	163	175
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	275	132	98
Proceeds from asset sales, net	0	18	3
(Increase) decrease in restricted cash	5,148	(5,148)	335
Acquisitions, net of cash acquired/divestitures	6,078	0	(234)
Distributions from unconsolidated affiliates	8	0	0
Other investing	3	0	0
Net cash provided by (used in) investing activities	(1,194)	(5,262)	474
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings	97	5,112	1,768
Proceeds from issuance of preferred stock	0	400	0
Proceeds from issuance of common stock	0	744	0
Repayments of borrowings, including debt extinguishment costs	(31)	(14)	(1,917)
Financing costs from debt issuance	(31)	(57)	0
Financing costs from equity issuance	(6)	(38)	0
Dividends paid	(23)	0	0
Interest rate swap settlement payments	(17)	(18)	(5)
Repurchase of common stock	(250)	0	0
Other financing	(4)	(3)	0
Net cash provided by (used in) financing activities	(265)	6,126	(154)
Net increase (decrease) in cash and cash equivalents	(1,365)	1,027	495
Cash and cash equivalents, beginning of period	1,870	843	348
Cash and cash equivalents, end of period	$ 505	$ 1,870	$ 843

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	Total	Preferred Stock	Common Stock
Stockholders' Equity Beginning balance at Dec. 31, 2012		$ 2,598	$ 11	$ (107)	$ 2,503			$ 0	$ 1
Noncontrolling interest at beginning of the period at Dec. 31, 2012						$ 0
Total Equity at the beginning of the period at Dec. 31, 2012							$ 2,503
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to Dynegy Inc.	$ (356)	0	0	(356)	(356)	0		0	0
Net income (loss)	(356)						(356)
Acquisitions		0	0	0	0	(4)	(4)	0	0
Other comprehensive loss, net of tax, attributable to parent	47	0	47	0	47			0	0
Other comprehensive loss, net of tax, attributable to noncontrolling interest						1
Other comprehensive income (loss), net of tax	48						48
Share-based compensation expense, net of tax		(14)	0	0	(14)	0	(14)	0	0
Options exercised		(2)	0	0	(2)	0	(2)	0	0
Stockholders' Equity Ending balance at Dec. 31, 2013		2,614	58	(463)	2,210			0	1
Noncontrolling interest at the end of the period at Dec. 31, 2013						(3)
Total Equity at the end of the period at Dec. 31, 2013							2,207
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to Dynegy Inc.	(273)	0	0	(273)	(273)	6		0	0
Net income (loss)	(267)						(267)
Other comprehensive loss, net of tax, attributable to parent	(38)	0	(38)	0	(38)			0	0
Other comprehensive loss, net of tax, attributable to noncontrolling interest						(3)
Other comprehensive income (loss), net of tax	(41)						(41)
Share-based compensation expense, net of tax		(17)	0	0	(17)	0	(17)	0	0
Options exercised		(1)	0	0	(1)	0	(1)	0	0
Issuance of new equity interests		(706)	0	0	(1,106)	0	(1,106)	(400)	0
Stockholders' Equity Ending balance at Dec. 31, 2014	3,023	3,338	20	(736)	3,023			400	1
Noncontrolling interest at the end of the period at Dec. 31, 2014	0					0
Total Equity at the end of the period at Dec. 31, 2014	3,023						3,023
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net loss attributable to Dynegy Inc.	50	0	0	50	50	(3)		0	0
Net income (loss)	47						47
Acquisitions		99	0	0	99	0	99	0	0
Other comprehensive loss, net of tax, attributable to parent	(1)	0	(1)	0	(1)			0	0
Other comprehensive loss, net of tax, attributable to noncontrolling interest						1
Other comprehensive income (loss), net of tax	0						0
Share-based compensation expense, net of tax		(22)	0	0	(22)	0	(22)	0	0
Options exercised		(1)	0	0	(1)	0	(1)	0	0
Dividends paid		(23)	0	0	(23)	0	(23)	0	0
Repurchases of common stock	(250)	(250)	0	0	(250)	0	(250)	0	0
Stockholders' Equity Ending balance at Dec. 31, 2015	2,921	$ 3,187	$ 19	$ (686)	$ 2,921			$ 400	$ 1
Noncontrolling interest at the end of the period at Dec. 31, 2015	(2)					$ (2)
Total Equity at the end of the period at Dec. 31, 2015	$ 2,919						$ 2,919

Organization and Operations

Organization and Operations	12 Months Ended
	Dec. 31, 2015
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 three segments in our consolidated financial statements: (i) the Coal segment (“Coal”), (ii) the IPH segment (“IPH”) and (iii) the Gas segment (“Gas”). Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 23—Segment Information for further discussion. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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. Intercompany accounts and transactions have been eliminated. Certain prior period amounts in our consolidated balance sheets 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, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and, indemnifications and (vi) 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, 2015, we had $39 million of restricted cash classified as current assets related to cash deposits associated with certain letters of credit. We included this change in restricted cash as an operating activity in our consolidated statements of cash flows. As of December 31, 2014, we had $5.1 billion of restricted cash classified as long-term assets and $113 million of prepaid interest classified as current assets related to the issuance of the Notes, as defined herein. Upon the close of the Acquisitions, as defined herein, the proceeds from the issuance of the Notes were released from escrow. Please read Note 13—Debt for further information. We included the changes in restricted cash related to the payment to the escrow agents for the Acquisitions and the prepayment of interest on the Notes as investing activities in our consolidated statements of cash flows. Payments to the escrow agents for interest accrued on the Notes are reflected as operating activities in our consolidated statements of cash flows. Accounts Receivable and Allowance for Doubtful Accounts. We record accounts receivable at the 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 two to 40 years. The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 2 to 36 Buildings and improvements 2 to 40 Office and other equipment 3 to 20 Gains and losses on sales of individual assets or asset groups 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 such assets may not be recoverable. If an impairment is indicated, the carrying value is first compared to the undiscounted cash flows for the asset’s or asset group’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 or asset group’s fair value. As a result of our impairment analyses performed in 2015, we determined that our Brayton Point and Wood River facilities were impaired resulting in an aggregate impairment charge of $99 million for the year ended December 31, 2015. Please read Note 9—Property, Plant and Equipment for further information. Goodwill. Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of net assets acquired. The carrying amount of our goodwill will be periodically reviewed, at least annually, for impairment and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In accordance with Accounting Standards Codification (“ASC”) 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment or we can directly perform a two-step impairment test. Based on our qualitative assessment, if we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent) to be less than its carrying amount, the two-step impairment test will be performed. In the absence of sufficient qualitative factors, goodwill impairment is determined using a two-step process: • Step one—Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. • Step two—Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess. As of December 31, 2015, we concluded that, due to the decrease in our stock price, it was more likely than not that the fair value of goodwill attributed to the reporting units in the Gas segment was less than its carrying amount. As a result, we performed a quantitative impairment analysis using a Discounted Cash Flow (“DCF”) model for each of the reporting units to which we assigned goodwill and determined that the fair value of the reporting units exceeded their respective carrying amounts, inclusive of goodwill. Therefore, as of December 31, 2015 , no impairment loss related to goodwill was required. Intangible Assets and Liabilities. We initially record and measure intangible assets and liabilities (“Intangibles”) based on the fair value of those rights transferred in the transaction in which the asset was acquired. All recognized Intangibles consist of contractual rights and obligations with finite lives. The Intangibles 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 based on the useful life of the respective contract or contracts. Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our consolidated balance sheets as liabilities when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundments and landfill closure, dismantlement of power generation facilities, future removal of asbestos-containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land obligations. Accretion expense is included in Operating and maintenance expense on our consolidated statements of operations. A summary of changes in our AROs is as follows: Year Ended December 31, (amounts in millions) 2015 2014 Balance at beginning of year $ 224 $ 181 Accretion expense 21 12 Liabilities incurred 4 — Liabilities settled (4 ) (2 ) Revision of previous estimate (1) (57 ) 33 Acquisitions (2) 92 — Balance at end of year $ 280 $ 224 __________________________________________ (1) During 2015, we revised our ARO downward by $57 million based on management’s review and assessment of CCR compliance timing and site-specific analysis. During 2014, we revised our ARO upward by $33 million based on observed trends in Illinois, primarily related to CCR surface impoundment closures and landfills in accordance with the standards used in the industry. (2) As a result of the Acquisitions in April 2015, the associated AROs were assumed. Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits 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 on 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 for litigation matters, 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 disclose and account for various guarantees and indemnifications entered into during the course of business. When a guarantee or indemnification is entered into, an estimated fair value of the underlying guarantee or indemnification is recorded. Some guarantees and indemnifications could have significant financial impact under certain circumstances; however, management also considers the probability of such circumstances occurring when estimating the fair value. Preferred Stock. Our preferred shares are mandatorily convertible, are not redeemable and are classified as stockholders’ equity. We present the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares are cumulative and are presented as a reduction of net income (or increase of net loss) to derive net income (loss) attributable to common shareholders on the consolidated statements of operations. Dividends are recognized in stockholders’ equity in the period in which they are declared, and are presented as a financing activity on the consolidated statements of cash flows when paid. Treasury Stock. Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented on 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 on 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 earnings. 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 and cap agreements. We elect not to apply hedge accounting to our interest rate derivative contracts; therefore, changes in fair value are recorded currently in earnings through interest expense. Cash settlements related to our current interest rate contracts are classified as either inflows or outflows from financing activities on the consolidated cash flow statements due to an other-than-insignificant financing element at inception of these contracts. 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. IPH and its subsidiaries (ring-fenced entities) operate under a tax sharing agreement with Dynegy. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences as of each reporting date. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation for tax and accounting purposes. These differences can result in deferred tax assets and liabilities which are included within our consolidated balance sheets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In making this determination, we consider all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies. Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. Please read Note 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 stock options and warrants are exercised and restricted stock units and performance stock units are fully vested under the treasury stock method. Diluted earnings (loss) per share also includes the effect of the assumed conversion of our convertible preferred stock 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. Accounting Standards Adopted Income Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17-Income Taxes (Topic 740). The amendment in this ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The guidance in this ASU is effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The ASU may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 as of December 31, 2015 and applied the guidance prospectively with no change to prior period amounts disclosed in our consolidated balance sheets and related notes to the consolidated financial statements. Please read Note 14—Income Taxes for further discussion. Business Combinations. In September 2015, the FASB issued ASU 2015-16-Business Combinations (Topic 805). The amendments in this ASU require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this ASU require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted for financial statements that have not been issued. We adopted ASU 2015-16 as of September 30, 2015. Please read Note 3—Acquisitions for a summary of the impact on our consolidated financial statements. Derivatives. In August 2015, the FASB issued ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of LMP by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our consolidated financial statements. Inventory. In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost or NRV, with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Retirement Benefits. In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this ASU provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this ASU. The amendments in this ASU are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this ASU should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted the guidance in this ASU on January 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements or disclosures. Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in these ASUs is effective for interim and annual periods beginning after December 15, 2015, with early adoption

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions	Note 3—Acquisitions Energy Capital Partners (“ECP”) Purchase Agreements. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of the stock purchase agreement dated August 21, 2014, as amended (the “ERC Purchase Agreement”), our wholly-owned subsidiary, Dynegy Resource II, LLC (the “ERC Purchaser”) purchased 100 percent of the equity interests in EquiPower Resources Corp. (“ERC”) from certain affiliates of ECP (collectively, the “ERC Sellers”) thereby acquiring: (i) five combined cycle natural-gas fired facilities in Connecticut, Massachusetts and Pennsylvania, (ii) a partial interest in one natural gas-fired peaking facility in Illinois, (iii) two gas and oil fired peaking facilities in Ohio and (iv) one coal-fired facility in Illinois (the “ERC Acquisition”). On the EquiPower Closing Date, in a related transaction, pursuant to a stock purchase agreement and plan of merger dated August 21, 2014, as amended (the “Brayton Purchase Agreement” and together with the ERC Purchase Agreement, the “ECP Purchase Agreements”) our wholly-owned subsidiary, Dynegy Resource III, LLC (the “Brayton Purchaser” and, together with the ERC Purchaser, the “ECP Purchasers”) purchased 100 percent of the equity interests in Brayton Point Holdings, LLC (“Brayton”) from certain affiliates of ECP (collectively, the “Brayton Sellers” and together with the ERC Sellers, the “ECP Sellers”), thereby acquiring a coal-fired facility in Massachusetts (the “Brayton Acquisition”). The ERC Acquisition and the Brayton Acquisition (collectively, the “EquiPower Acquisition”) added approximately 6,300 MW of generation in Connecticut, Illinois, Massachusetts, Ohio and Pennsylvania for an aggregate base purchase price of approximately $3.35 billion in cash plus approximately $105 million in common stock of Dynegy, subject to certain adjustments. In aggregate, the resulting operations from the two coal-fired facilities acquired from the ECP Sellers are reported within our Coal segment, while related operations from the six natural gas-fired and two gas and oil-fired facilities are reported within our Gas segment. Under the ECP Purchase Agreements, the ECP Purchasers and ECP Sellers have agreed to indemnify the other applicable parties for breaches of representations and warranties, breaches of covenants and certain other matters, subject to certain exceptions and limitations. Neither the ECP Purchasers nor the ECP Sellers, in the aggregate, are entitled to indemnification in excess of $276 million , and $104 million of the purchase price which will be held in escrow for one year after closing to support the post-closing adjustment and indemnification obligations of the ECP Sellers. Duke Midwest Purchase Agreement. On April 2, 2015 (the “Duke Midwest Closing Date”), pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended (the “Duke Midwest Purchase Agreement”), our wholly owned subsidiary Dynegy Resource I, LLC (“DRI”) purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation including: (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. We operate two of the five coal-fired facilities, the Miami Fort and Zimmer facilities, with other owners operating the three remaining facilities. The operations from the retail energy business, the five coal-fired and the one oil-fired facilities acquired from Duke Energy are reported within our Coal segment, while related operations from the five natural gas-fired facilities are reported within our Gas segment. Under the Duke Midwest Purchase Agreement, DRI and Duke Energy have agreed to indemnify the other applicable parties for breaches of representations and warranties, breaches of covenants and certain other matters, subject to certain exceptions and limitations. Dynegy has guaranteed, up to a maximum liability of $2.8 billion , the Obligations of DRI under the Duke Midwest Purchase Agreement and related Transition Services Agreement (“TSA”). DRI shall, in the aggregate, not be entitled to indemnification in excess of $280 million for most matters and $2.8 billion for certain fundamental representations, tax matters and fraud. Business Combinations Accounting. The EquiPower Acquisition and the Duke Midwest Acquisition (collectively, the “Acquisitions”) have been accounted for in accordance with ASC 805, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition dates, April 1, 2015 and April 2, 2015, respectively. The valuation of these assets and liabilities is classified as Level 3 within the fair value hierarchy levels. The initial accounting for the Acquisitions is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the second quarter of 2016. The significant assets and liabilities for which provisional amounts are recognized at the respective acquisition dates are PP&E, goodwill, deferred income taxes and taxes other than deferred income taxes. We continue to evaluate settlements which could relate to pre-acquisition activity from the ISOs. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E, goodwill or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuations are completed, not to exceed one year, and any material adjustments identified that existed as of the acquisition date will be recognized in the current period. To fair value working capital, we used available market information. ARO’s were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations. To fair value the acquired PP&E, we used a DCF analysis based upon a debt-free, free cash flow model. The DCF model was created for each power generation facility based on its remaining useful life, and included gross margin forecasts for each facility using forward commodity market prices obtained from third party quotations for the years 2015 through 2016. For the years 2017 through 2024, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward NYMEX natural gas prices and supply and demand factors. For periods beyond 2024, we assumed a 2.5 percent growth rate. We also used management’s forecasts of operations and maintenance expense, general and administrative expense and capital expenditures for the years 2015 through 2019 and assumed a 2.5 percent growth rate, based upon management’s view of future conditions, thereafter. The resulting cash flows were then discounted using plant specific discount rates of approximately 8 percent to 10 percent for gas-fired generation facilities and approximately 9 percent to 13 percent for coal-fired generation facilities, based upon the asset’s age, efficiency, region and years until retirement. Contracts with terms that are not at current market prices were also valued using a DCF analysis. The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability. The 3,460,053 shares of common stock of Dynegy issued as part of the consideration for the EquiPower Acquisition were valued at approximately $105 million based on the closing price of Dynegy’s common stock on the EquiPower Closing Date. The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 127 176 Inventory 167 105 272 Assets from risk management activities (including current portion of $4 million and $30 million, respectively) 4 33 37 Prepayments and other current assets 32 69 101 Property, plant and equipment 2,773 2,734 5,507 Investment in unconsolidated affiliate 200 — 200 Intangible assets (including current portion of $67 million and $36 million, respectively) 111 84 195 Other long-term assets 28 35 63 Total assets acquired 3,631 3,187 6,818 Accounts payable 27 97 124 Accrued liabilities and other current liabilities 22 10 32 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 506 — 506 Other long-term liabilities — 40 40 Total liabilities assumed 767 396 1,163 Identifiable net assets acquired 2,864 2,791 5,655 Goodwill 797 — 797 Net assets acquired $ 3,661 $ 2,791 $ 6,452 As a result of recording the stepped up fair market basis for GAAP purposes, but receiving primarily carryover basis for tax purposes in the EquiPower Acquisition, we initially recorded a net deferred tax liability of $537 million within our provisional valuation of the EquiPower Acquisition as of the acquisition date. As we had previously recorded a valuation allowance against our historical deferred tax assets, we released approximately $480 million of our valuation allowance as a result of these increased deferred tax liabilities during the second quarter of 2015. During the second half of 2015, we reduced the initially-recognized deferred tax liability by $31 million due to newly available information regarding the fair values of assets and liabilities acquired in the EquiPower Acquisition. This reduction to the deferred tax liability resulted primarily in a corresponding reduction to goodwill, as discussed below, and a $27 million reversal of the previously released valuation allowance discussed above. As of December 31, 2015 , we have recorded a net deferred tax liability of $506 million and released approximately $453 million of our valuation allowance related to the EquiPower Acquisition. Goodwill resulting from the EquiPower Acquisition reflects the excess of our purchase price over the fair value of the net assets acquired. We recorded initial goodwill of $837 million as of the acquisition date, and subsequently reduced the amount during the second half of 2015 by $40 million due to the newly available information discussed above. As of December 31, 2015 , we have recognized goodwill of $797 million related to the EquiPower Acquisition, all of which is allocated to our Gas reporting segment. None of the goodwill recognized is deductible for income tax purposes, and as such, no deferred taxes related to goodwill have been recorded. No goodwill was recognized as a result of the Duke Midwest Acquisition. We incurred acquisition costs of $86 million and $19 million for the years ended December 31, 2015 and 2014 , respectively, related to the Acquisitions, which are included in Acquisition and integration costs on our consolidated statements of operations. Acquisition costs for the year ended December 31, 2015 include $48 million of commitment fees associated with a temporary bridge facility, which were payable only upon the closing of the Acquisitions. No amounts were borrowed under the bridge facility, and the bridge facility was cancelled, as our permanent financing for the Acquisitions was executed. Revenues of $1.623 billion and operating income of $154 million attributable to the Acquisitions for the year ended December 31, 2015 are included in our consolidated statement of operations. Pro Forma Results. The unaudited pro forma financial results for the years ended December 31, 2015 and 2014 assume the EquiPower Acquisition and the Duke Midwest Acquisition occurred on January 1, 2014. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisitions been completed on January 1, 2014, nor are they indicative of future results of operations. Year Ended December 31, (amounts in millions) 2015 2014 Revenues $ 4,860 $ 5,574 Net income (loss) $ 308 $ (613 ) Net income (loss) attributable to noncontrolling interest $ (3 ) $ 6 Net income (loss) attributable to Dynegy Inc. $ 311 $ (619 ) AER Transaction Agreement. On December 2, 2013, pursuant to the terms of the definitive agreement dated as of March 14, 2013 and as amended on December 2, 2013 (the “AER Transaction Agreement”) by and between IPH, an indirect wholly-owned subsidiary of Dynegy, and Ameren Corporation (“Ameren”), IPH completed its acquisition from Ameren of 100 percent of the equity interests of New Ameren Energy Resources, LLC (“AER”) and its subsidiaries (the “AER Acquisition”). The acquisition added 4,062 MW of generation in Illinois and also included the Homefield Energy retail business. There was no cash consideration or stock issued as part of the purchase price. We acquired AER and its subsidiaries through IPH, which will maintain corporate separateness from our legal entities outside of IPH. We incurred acquisition costs of $16 million and $20 million related to the AER Acquisition, which are included in Acquisition and integration costs on our consolidated statements of operations for the years ended December 31, 2014 and 2013 , respectively. Revenues of $846 million and $67 million and operating losses of $2 million and $17 million attributable to IPH are included in our consolidated statements of operations for the years ended December 31, 2014 and 2013, respectively. Please read Note 23—Segment Information for further discussion.

Risk Management Activities, Der

Risk Management Activities, Derivatives, and Financial Instruments	12 Months Ended
	Dec. 31, 2015
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 necessarily involves commodity market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk. Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one - to three -year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term. Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our consolidated statements of operations. We have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases and retail power sales which do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale,” 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, 2015 , 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) (45 ) MWh $ (1 ) Electricity basis derivatives (3) (29 ) MWh $ 24 Natural gas derivatives (2) 305 MMBtu $ (143 ) Natural gas basis derivatives 69 MMBtu $ (7 ) Diesel fuel 3 Gallon $ (4 ) Coal derivatives (4) — Metric Ton $ (23 ) Interest rate swaps 777 U.S. Dollar $ (42 ) Common stock warrants (5) 16 Warrant $ (7 ) _________________________________________ (1) Includes both asset and liability risk management positions, but excludes margin and collateral netting of $106 million . (2) Mainly comprised of swaps, options and physical forwards. (3) Comprised of FTRs and swaps. (4) Our net position rounds to less than 1 million tons. (5) Each warrant is convertible into one share of Dynegy common stock. Derivatives on the Balance Sheet. The following table presents the fair value and balance sheet classification of derivatives in our consolidated balance sheets as of December 31, 2015 and 2014 . As of December 31, 2015 and 2014 , there were no gross amounts available to be offset that were not offset in our consolidated balance sheets. December 31, 2015 Gross amounts offset in the balance sheet Contract Type Balance Sheet Location Gross Fair Value Contract Netting Collateral or Margin Received or Paid Net Fair Value (amounts in millions) Derivative assets: Commodity contracts Assets from risk management activities $ 403 $ (285 ) $ $ 118 Total derivative assets $ 403 $ (285 ) $ — $ 118 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (557 ) $ 285 $ 106 $ (166 ) Interest rate contracts Liabilities from risk management activities (42 ) — — (42 ) Common stock warrants Other long-term liabilities (7 ) — — (7 ) Total derivative liabilities $ (606 ) $ 285 $ 106 $ (215 ) Total derivatives $ (203 ) $ $ 106 $ (97 ) December 31, 2014 Gross amounts offset in the balance sheet Contract Type Balance Sheet Location Gross Fair Value Contract Netting Collateral or Margin Received or Paid Net Fair Value (amounts in millions) Derivative assets: Commodity contracts Assets from risk management activities $ 115 $ (35 ) $ $ 80 Total derivative assets $ 115 $ (35 ) $ — $ 80 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (163 ) $ 35 $ 9 $ (119 ) Interest rate contracts Liabilities from risk management activities (44 ) — — (44 ) Common stock warrants Other long-term liabilities (61 ) — — (61 ) Total derivative liabilities $ (268 ) $ 35 $ 9 $ (224 ) Total derivatives $ (153 ) $ $ 9 $ (144 ) Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position that are not fully collateralized (excluding transactions with our clearing brokers that are fully collateralized) as of December 31, 2015 is $49 million for which we have posted $21 million in collateral. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program. The following table summarizes our cash collateral posted as of December 31, 2015 and 2014 , within Prepayments and other current assets on our consolidated balance sheets, and the amount applied against short-term risk management activities: Location on balance sheet December 31, 2015 December 31, 2014 (amounts in millions) Gross collateral posted with counterparties $ 162 $ 49 Less: Collateral netted against risk management liabilities 106 9 Net collateral within Prepayments and other current assets $ 56 $ 40 Impact of Derivatives on the Consolidated Statements of Operations The following discussion and table present the location and amount of gains and losses on derivative instruments in our consolidated statements of operations. Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within our consolidated statements of operations. Our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 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, 2015 2014 2013 (amounts in millions) Commodity contracts Revenues $ 194 $ (183 ) $ (101 ) Interest rate contracts Interest expense $ (15 ) $ (15 ) $ (7 ) Common stock warrants Other income (expense), net $ 54 $ (40 ) $ (1 )

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 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, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 308 $ 40 $ 348 Natural gas derivatives — 40 2 42 Coal derivatives — 10 3 13 Total assets from commodity risk management activities $ — $ 358 $ 45 $ 403 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (267 ) $ (58 ) $ (325 ) Natural gas derivatives — (158 ) (34 ) (192 ) Diesel fuel derivatives — (4 ) — (4 ) Coal derivatives — (35 ) (1 ) (36 ) Total liabilities from commodity risk management activities — (464 ) (93 ) (557 ) Liabilities from interest rate contracts — (42 ) — (42 ) Liabilities from outstanding common stock warrants (7 ) — — (7 ) Total liabilities $ (7 ) $ (506 ) $ (93 ) $ (606 ) Fair Value as of December 31, 2014 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 88 $ 22 $ 110 Natural gas derivatives — 3 — 3 Emissions derivatives — 2 — 2 Total assets from commodity risk management activities $ — $ 93 $ 22 $ 115 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (27 ) $ (26 ) $ (53 ) Natural gas derivatives — (100 ) — (100 ) Diesel fuel derivatives — (6 ) — (6 ) Crude oil derivatives — (3 ) — (3 ) Coal derivatives — (1 ) — (1 ) Total liabilities from commodity risk management activities — (137 ) (26 ) (163 ) Liabilities from interest rate contracts — (44 ) — (44 ) Liabilities from outstanding common stock warrants (61 ) — — (61 ) Total liabilities $ (61 ) $ (181 ) $ (26 ) $ (268 ) Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts, heat rate derivatives and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. The forward market price of FTRs is derived using historical congestion patterns within the marketplace and heat rate derivative valuations are derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities and modeled correlation values. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps and physical purchases executed in illiquid trading locations or on long dated contracts. The coal derivatives classified within Level 3 include financial swaps executed in illiquid trading locations. Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, natural gas and coal pricing and the difference between our plant locational prices to liquid hub prices. Power price spreads, natural gas and coal pricing and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of December 31, 2015 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Inputs Significant Unobservable Inputs Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (4 ) Million MWh $ (11 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs 24 Million MWh $ (7 ) Historical congestion Forward price $0 - $1.00 Natural gas derivatives (1) 96 Million MMBtu $ (32 ) Illiquid location fixed price Forward price $1.40 - $1.70 Coal derivatives (1) — Thousand Tons $ 2 Illiquid location fixed price Forward price $4.35 - $5.35 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations. The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy: Year Ended December 31, 2015 (amounts in millions) Electricity Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Total gains included in earnings 39 3 — — 42 Settlements (1) 1 28 9 (2 ) 36 Acquisitions (54 ) (63 ) (9 ) 4 (122 ) Balance at December 31, 2015 $ (18 ) $ (32 ) $ — $ 2 $ (48 ) Unrealized gains relating to instruments held as of December 31, 2015 $ 39 $ 3 $ — $ — $ 42 Year Ended December 31, 2014 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2013 $ 11 $ — $ (1 ) $ — $ 10 Total gains (losses) included in earnings (9 ) — 1 — (8 ) Settlements (1) (6 ) — — — (6 ) Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Unrealized gains (losses) relating to instruments held as of December 31, 2014 $ (9 ) $ — $ 1 $ — $ (8 ) Year Ended December 31, 2013 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2012 $ 5 $ — $ 2 $ — $ 7 Total gains (losses) included in earnings (4 ) — 1 — (3 ) Settlements (1) (6 ) — (3 ) — (9 ) AER Acquisition 16 — (1 ) — 15 Balance at December 31, 2013 $ 11 $ — $ (1 ) $ — $ 10 Unrealized gains (losses) relating to instruments held as of December 31, 2013 $ (4 ) $ — $ 1 $ — $ (3 ) __________________________________________ (1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period. Gains and losses recognized for Level 3 recurring items are included in Revenues in our consolidated statements of operations for commodity derivatives. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any transfers between Level 1, Level 2 and Level 3 for the years ended December 31, 2015 and 2014 . Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. During December 31, 2015 and 2014 , we measured at fair value on a nonrecurring basis certain nonfinancial assets and liabilities. Our measurement of the provisional purchase price allocation is discussed in Note 3—Acquisitions , and the measurements of the Wood River Power Station and Brayton Point generation facilities are discussed in Note 9—Property, Plant and Equipment . Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments recognized on 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, 2015 and 2014 . December 31, 2015 December 31, 2014 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (2)(6) $ (2,100 ) $ (1,985 ) $ (2,100 ) $ (2,132 ) Tranche B-2 Term Loan, due 2020 (1)(2) $ (778 ) $ (754 ) $ (785 ) $ (775 ) 7.375% Senior Notes, due 2022 (2)(6) $ (1,750 ) $ (1,531 ) $ (1,750 ) $ (1,777 ) 5.875% Senior Notes, due 2023 (2) $ (500 ) $ (404 ) $ (500 ) $ (475 ) 7.625% Senior Notes, due 2024 (2)(6) $ (1,250 ) $ (1,078 ) $ (1,250 ) $ (1,272 ) Inventory financing agreements (2) $ (136 ) $ (136 ) $ (23 ) $ (23 ) Equipment financing agreements (7) $ (61 ) $ (61 ) $ — $ — Interest rate derivatives (2) $ (42 ) $ (42 ) $ (44 ) $ (44 ) Commodity-based derivative contracts (3) $ (154 ) $ (154 ) $ (48 ) $ (48 ) Common stock warrants (4) $ (7 ) $ (7 ) $ (61 ) $ (61 ) Genco: 7.00% Senior Notes Series H, due 2018 (2)(5) $ (276 ) $ (204 ) $ (268 ) $ (264 ) 6.30% Senior Notes Series I, due 2020 (2)(5) $ (213 ) $ (148 ) $ (206 ) $ (208 ) 7.95% Senior Notes Series F, due 2032 (2)(5) $ (225 ) $ (162 ) $ (224 ) $ (241 ) __________________________________________ (1) Carrying amount includes an unamortized discount of $2 million and $3 million as of December 31, 2015 and 2014 , respectively. Please read Note 13—Debt for further discussion. (2) The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels. (3) Carrying amount of commodity-based derivative contracts excludes $106 million and $9 million of cash posted as collateral, as of December 31, 2015 and 2014 , respectively. (4) The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels. (5) Combined carrying amounts as of December 31, 2015 and 2014 include unamortized discounts of $111 million and $127 million , respectively. Please read Note 13—Debt for further discussion. (6) At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”). (7) Carrying amounts for the equipment financing agreements include unamortized discounts of $14 million as of December 31, 2015 . In addition, the fair value is classified as Level 3 within the fair value hierarchy levels. 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, 2015 and 2014 , our credit exposure as it relates to the mark-to-market portion of our risk management portfolio totaled $45 million and $12 million , respectively. We seek to reduce our credit exposure by executing agreements that permit us to offset receivables, payables and mark-to-market exposure. 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. Our Credit Department, based on guidelines approved by the Board of Directors, establishes our counterparty credit limits. Our industry typically operates under negotiated credit lines for physical delivery and financial contracts. Our credit risk system provides current credit exposure to counterparties on a daily basis. 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. 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 on our consolidated balance sheets. As of December 31, 2015 and 2014 , we had $56 million and $40 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 on our consolidated balance sheets. As of December 31, 2015 , we were not holding any collateral received from counterparties.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Note 6—Accumulated Other Comprehensive Income Changes in accumulated other comprehensive income (“AOCI”), net of tax, by component are as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Beginning of period $ 20 $ 58 $ 11 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments (net of tax of zero, zero and $31, respectively) 3 (33 ) 56 Amounts reclassified from accumulated other comprehensive income: Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively) (1) — — (7 ) Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero and zero, respectively) (2) (4 ) (5 ) (2 ) Net current period other comprehensive income (loss), net of tax (1 ) (38 ) 47 End of period (3) $ 19 $ 20 $ 58 __________________________________________ (1) Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion. (3) Includes a tax impact of $31 million due to remeasurements of certain of our pension and other post-employment benefit plans in 2013 that will only reverse if and when the Dynegy plans terminate.

Cash Flow Information

Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [Abstract]
Cash Flow Information	Note 7—Cash Flow Information The supplemental disclosures of cash flow and non-cash investing and financing information are as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Interest paid (net of amount capitalized) $ 491 $ 120 $ 92 Taxes paid (net of refunds) $ 2 $ — $ (1 ) Other non-cash investing and financing activity: Non-cash capital expenditures (1) $ 10 $ 23 $ (3 ) Non-cash capital expenditures pursuant to an equipment financing agreement $ 61 $ — $ — Acquisition consideration (2) $ 105 $ — $ 7 __________________________________________ (1) These expenditures are primarily for changes in our accruals of capital expenditures for all years presented. (2) Represents the consideration given by us for acquisitions. Please read Note 3—Acquisitions for further discussion.

Inventory

Inventory	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventory	Note 8—Inventory A summary of our inventories is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Materials and supplies $ 175 $ 83 Coal (1) 350 119 Fuel oil (1) 17 3 Emissions allowances (2) 51 2 Other 4 1 Total $ 597 $ 208 __________________________________________ (1) At December 31, 2015 , approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt —Brayton Point Inventory Financing for further discussion. (2) At December 31, 2015 , a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt —Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Note 9—Property, Plant and Equipment A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Power generation $ 8,178 $ 3,174 Buildings and improvements 956 457 Office and other equipment 101 54 Property, plant and equipment 9,235 3,685 Accumulated depreciation (888 ) (430 ) Property, plant and equipment, net $ 8,347 $ 3,255 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) 2015 2014 2013 Total interest costs incurred $ 487 $ 187 $ 86 Capitalized interest $ 12 $ 9 $ 2 On November 5, 2015 , Dynegy announced that it expects to retire the final two units at its Wood River Power Station (“Wood River”) in mid-2016, subject to the approval of MISO. The decision to retire Wood River was the result of a strategic review performed in the third quarter of 2015, and was primarily attributable to its uneconomic operation stemming from a poorly designed wholesale capacity market. As a result of these factors, we performed an impairment analysis, which indicated that Wood River had a negative fair value. Therefore, we recorded an impairment charge of $74 million in Impairments in our consolidated statements of operations for the year ended December 31, 2015 to write off the entire carrying value. The fair value of Wood River was determined using a DCF model, utilizing a 12 percent discount rate, and assuming normal operations for the remainder of its estimated useful life. For the model, gross margin was based on publicly available forward market quotes, operations and maintenance expenses were based on current forecasts, and capital expenditures assumed the minimum of cash expenditures required to continue running the plant until its anticipated retirement. The valuation is classified as Level 3 within the fair value hierarchy levels. In the fourth quarter of 2015, Dynegy’s Brayton Point generation facility’s operating area experienced significantly warmer weather than normal, resulting in lowered demand and power prices for the period. Dynegy has previously disclosed plans to retire the facility in June 2017, thus the temperate weather had a significant impact on the facility’s remaining cash flows, resulting in an impairment trigger. We performed step one of the impairment analysis using undiscounted cash flows for the facility’s remaining operational years, and determined the book value of the asset would not be recovered. We performed step two of the impairment analysis using a DCF model, utilizing a 9 percent discount rate, and assuming normal operations for the remainder of its estimated useful life. For the model, gross margin was based on publicly available forward market quotes, operations and maintenance expenses were based on current forecasts, and capital expenditures assumed the minimum of cash expenditures required to continue running the plant until its anticipated retirement. The model resulted in a fair value of the facility of $86 million ; therefore, we recorded an impairment charge of $25 million in Impairments in our consolidated statements of operations for the year ended December 31, 2015 to reduce the carrying value of the Brayton Point facility. The valuation is classified as Level 3 within the fair value hierarchy levels.

Joint Ownership of Generating F

Joint Ownership of Generating Facilities	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Joint Ownership of Generating Facilities	Note 10—Joint Ownership of Generating Facilities We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Our share of revenues and operating costs of the jointly owned generating facilities are included within the corresponding financial statement line items in our consolidated statements of operations. The following table presents the ownership interests of the jointly owned facilities included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy. Note 11—Unconsolidated Investments Equity Method Investments Elwood. In connection with the EquiPower Acquisition, we acquired a 50 percent interest in Elwood Energy LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (“Elwood Expansion” and, together with Elwood Energy, “Elwood”). Elwood Energy owns a 1,576 MW natural gas-fired facility located in Elwood, Illinois. As of December 31, 2015 , our investment was $190 million . Upon the acquisition of our Elwood investment, we recognized basis differences in the net assets of approximately $89 million related to working capital, property plant and equipment, debt and intangibles. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. Holders of the debt of our unconsolidated investment do not have recourse to us and our other subsidiaries; therefore, the debt of our unconsolidated investment is not reflected in our consolidated balance sheets. We recorded $1 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our consolidated statement of operations for the year ended December 31, 2015 . For the year ended December 31, 2015 , we received a distribution of $11 million , of which $8 million was considered a return of investment. As of December 31, 2015 we have approximately $3 million in accounts receivable due from Elwood, which is included in Accounts receivable in our consolidated balance sheets. Black Mountain. On June 27, 2014, we completed the sale of our 50 percent partnership interest in Nevada Cogeneration Associates #2, a partnership that owns Black Mountain, an 85 MW ( 43 net MW) natural gas-fired combined cycle gas turbine facility in Nevada. We received $17 million in cash proceeds upon the close of the transaction, which is reflected in Gain on sale of assets, net in our consolidated statements of operations for the year ended December 31, 2014 . In connection with the sale, our guarantee was terminated. Additionally, we received $10 million in cash distributions from Black Mountain, which is recorded as Earnings (losses) from unconsolidated investments in our consolidated statements of operations for the year ended December 31, 2014 .

Unconsolidated Investments

Unconsolidated Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Unconsolidated Investments	Note 10—Joint Ownership of Generating Facilities We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to the additional costs. Our share of revenues and operating costs of the jointly owned generating facilities are included within the corresponding financial statement line items in our consolidated statements of operations. The following table presents the ownership interests of the jointly owned facilities included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy. Note 11—Unconsolidated Investments Equity Method Investments Elwood. In connection with the EquiPower Acquisition, we acquired a 50 percent interest in Elwood Energy LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (“Elwood Expansion” and, together with Elwood Energy, “Elwood”). Elwood Energy owns a 1,576 MW natural gas-fired facility located in Elwood, Illinois. As of December 31, 2015 , our investment was $190 million . Upon the acquisition of our Elwood investment, we recognized basis differences in the net assets of approximately $89 million related to working capital, property plant and equipment, debt and intangibles. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. Holders of the debt of our unconsolidated investment do not have recourse to us and our other subsidiaries; therefore, the debt of our unconsolidated investment is not reflected in our consolidated balance sheets. We recorded $1 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our consolidated statement of operations for the year ended December 31, 2015 . For the year ended December 31, 2015 , we received a distribution of $11 million , of which $8 million was considered a return of investment. As of December 31, 2015 we have approximately $3 million in accounts receivable due from Elwood, which is included in Accounts receivable in our consolidated balance sheets. Black Mountain. On June 27, 2014, we completed the sale of our 50 percent partnership interest in Nevada Cogeneration Associates #2, a partnership that owns Black Mountain, an 85 MW ( 43 net MW) natural gas-fired combined cycle gas turbine facility in Nevada. We received $17 million in cash proceeds upon the close of the transaction, which is reflected in Gain on sale of assets, net in our consolidated statements of operations for the year ended December 31, 2014 . In connection with the sale, our guarantee was terminated. Additionally, we received $10 million in cash distributions from Black Mountain, which is recorded as Earnings (losses) from unconsolidated investments in our consolidated statements of operations for the year ended December 31, 2014 .

Intangible Assets and Liabiliti

Intangible Assets and Liabilities	12 Months Ended
	Dec. 31, 2015
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Intangible Assets and Liabilities	Note 12—Intangible Assets and Liabilities The following table summarizes the components of our intangible assets and liabilities as of December 31, 2015 and 2014: December 31, 2015 December 31, 2014 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (126 ) $ 134 $ 111 $ (46 ) $ 65 Gas transport contracts 46 (16 ) 30 — — — Total intangible assets $ 306 $ (142 ) $ 164 $ 111 $ (46 ) $ 65 Intangible Liabilities: Electricity contracts $ (30 ) $ 19 $ (11 ) $ (20 ) $ 14 $ (6 ) Coal contracts (134 ) 82 (52 ) (41 ) 22 (19 ) Coal transport contracts (104 ) 64 (40 ) (81 ) 32 (49 ) Gas transport contracts (64 ) 27 (37 ) (24 ) 17 (7 ) Total intangible liabilities $ (332 ) $ 192 $ (140 ) $ (166 ) $ 85 $ (81 ) Intangible assets and liabilities, net $ (26 ) $ 50 $ 24 $ (55 ) $ 39 $ (16 ) The following table presents our amortization expense (revenue) of intangible assets and liabilities for the past three years during the years ended December 31, 2015, 2014 and 2013 : Year Ended December 31, (amounts in millions) 2015 2014 2013 Electricity contracts, net (1) $ 75 $ 96 $ 136 Coal contracts, net (2) (60 ) (14 ) 129 Coal transport contracts (2) (32 ) (29 ) (7 ) Gas transport contracts (2) 6 (8 ) (7 ) Total $ (11 ) $ 45 $ 251 __________________________________________ (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, 2015 is as follows: 2016 — $18 million , 2017 — $19 million , 2018 — $4 million , 2019 — zero and 2020 — $(2) million . The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the Acquisitions in April 2015: EquiPower Acquisition Duke Midwest Acquisition (amounts in millions/months) Gross Carrying Amount Weighted-Average Amortization Period Gross Carrying Amount Weighted-Average Amortization Period Intangible Assets: Electricity contracts $ 68 31 $ 80 38 Coal contracts — — — 9 Gas transport contracts 43 28 4 19 Total intangible assets $ 111 30 $ 84 37 Intangible Liabilities: Electricity contracts $ — — $ (10 ) 23 Coal contracts (10 ) 21 (83 ) 27 Coal transport contracts (23 ) 22 — — Gas contracts — 1 — — Gas transport contracts (40 ) 128 — — Total intangible liabilities $ (73 ) 81 $ (93 ) 27 Total intangible assets and liabilities, net $ 38 $ (9 )

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Note 13—Debt A summary of our long-term debt is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Dynegy Inc.: 6.75% Senior Notes, due 2019 (1) $ 2,100 $ 2,100 Tranche B-2 Term Loan, due 2020 780 788 7.375% Senior Notes, due 2022 (1) 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 (1) 1,250 1,250 Revolving Facility — — Inventory Financing Agreements 136 23 Equipment Financing Agreements 75 — Genco: 7.00% Senior Notes Series H, due 2018 300 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 7,416 7,236 Unamortized discounts on debt, net (127 ) (130 ) 7,289 7,106 Less: Current maturities, including unamortized discounts, net 83 31 Total Long-term debt $ 7,206 $ 7,075 __________________________________________ (1) At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”). Aggregate maturities of the principal amounts of all long-term indebtedness, excluding unamortized discounts, as of December 31, 2015 are as follows: 2016 — $83 million , 2017 — $55 million , 2018 — $359 million , 2019 — $2.116 billion , 2020 — $1.012 billion and thereafter — $3.791 billion . Debt Issuance On October 27, 2014, Dynegy Finance II, Inc. ( the “EquiPower Escrow Issuer”), a wholly-owned subsidiary of Dynegy, issued $3.06 billion in aggregate principal amount of senior notes, the proceeds of which were placed into escrow until the closing of the EquiPower Acquisition. On the EquiPower Closing Date, the proceeds from the issuance were released from escrow and used to pay a portion of the EquiPower Acquisition consideration and to pay fees and expenses. On the EquiPower Closing Date, Dynegy, as successor in interest to the EquiPower Escrow Issuer, executed supplemental indentures evidencing its accession to the 6.75 percent senior notes due 2019 (the “2019 Finance II Notes”), the 7.375 percent senior notes due 2022 (the “2022 Finance II Notes”), and the 7.625 percent senior notes due 2024 (the “2024 Finance II Notes” and, together with the 2019 Finance II Notes and the 2022 Finance II Notes, the “Finance II Notes”). Further, on October 27, 2014, Dynegy Finance I, Inc. (the “Duke Escrow Issuer”), a wholly-owned subsidiary of Dynegy, issued $2.04 billion in aggregate principal amount of senior notes, the proceeds of which were placed into escrow until the closing of the Duke Midwest Acquisition. On the Duke Midwest Closing Date, the proceeds from the issuance were released from escrow and used to pay a portion of the Duke Midwest Acquisition consideration and to pay fees and expenses. On the Duke Midwest Closing Date, Dynegy, as successor in interest to the Duke Escrow Issuer, executed supplemental indentures evidencing its accession to the 6.75 percent senior notes due 2019 (the “2019 Finance I Notes”), the 7.375 percent senior notes due 2022 (the “2022 Finance I Notes”), and the 7.625 percent senior notes due 2024 (the “2024 Finance I Notes” and, together with the 2019 Finance I Notes and the 2022 Finance I Notes, the “Finance I Notes”). Concurrently with Dynegy’s accession to the Finance I Notes, as successor in interest to the Duke Escrow Issuer, each series of Finance I Notes was automatically exchanged for an equal aggregate principal amount of Finance II Notes with the same terms, as applicable, issued by Dynegy. The additional Finance II Notes issued pursuant to such automatic exchanges were treated as a single class for all purposes and are fully fungible with the Finance II Notes with the same terms previously issued under the Finance II indentures. On the EquiPower Closing Date, generally, each of Dynegy’s current wholly-owned domestic subsidiaries that is a borrower or guarantor under Dynegy’s existing credit facilities (the “Dynegy Guarantors”), and the entities acquired in the EquiPower Acquisition (the “EquiPower Guarantors”) executed supplemental indentures evidencing their accession to the Finance II Notes as guarantors. Similarly, on the Duke Midwest Closing Date, each of Dynegy’s current wholly-owned domestic subsidiaries that is a borrower or guarantor under Dynegy’s existing credit facilities and the entities acquired in the Duke Midwest Acquisition (the “Duke Guarantors” and, together with the Dynegy Guarantors and the EquiPower Guarantors, the “Guarantors”) executed supplemental indentures evidencing their accession to the Finance I Notes and the Finance II Notes as guarantors. On the EquiPower Closing Date, the Dynegy Guarantors and the EquiPower Guarantors executed a joinder to the registration rights agreement, dated October 27, 2014, among the EquiPower Escrow Issuer, the Duke Escrow Issuer, and Morgan Stanley & Co. LLC, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, RBC Capital Markets, LLC and UBS Securities LLC as representatives of the initial purchasers identified therein (the “Registration Rights Agreement”). Additionally, on the Duke Midwest Closing Date, the Duke Guarantors executed a joinder to the Registration Rights Agreement. As required by the Registration Rights Agreement, on July 17, 2015, Dynegy commenced registered exchange offers for the Notes, which closed on August 17, 2015. The terms of the exchange notes are identical in all material respects to the terms of the Notes, except that the exchange notes have been registered under the Securities Act. We received no proceeds from these exchange offers. Credit Agreement As of December 31, 2015 , we had a $2.225 billion credit agreement that consisted of (i) an $800 million seven -year senior secured term loan B facility (the “Tranche B-2 Term Loan”) and (ii) a $1.425 billion five -year senior secured revolving credit facility (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). Dynegy and its Subsidiary Guarantors (as defined in the Credit Agreement) also entered into an indenture pursuant to which Dynegy issued $500 million in aggregate principal amount of unsecured senior notes (the “Senior Notes”) at par. Following the closings of the Acquisitions in April 2015, the acquired entities were added as additional subsidiary guarantors. At December 31, 2015 , there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit of approximately $420 million , which reduce the amount available under the Revolving Facility. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Based on the calculation outlined in the Credit Agreement, we are in compliance as of December 31, 2015 . Credit Agreement Amendments. On the EquiPower Closing Date, Dynegy entered into a First Amendment to the Credit Agreement (the “First Amendment”) among Dynegy, certain subsidiaries of Dynegy, the lenders party thereto, Credit Suisse AG, Cayman Islands Branch (“Credit Suisse”), as administrative agent, and the other parties thereto. The First Amendment provides for a new $350 million five -year senior secured incremental tranche of revolving commitments (the “Incremental Tranche A Revolving Loan Commitments”), which have terms substantially the same as the terms of the outstanding tranche of revolving loans under the Credit Agreement and will mature on April 1, 2020. Amounts available under the Incremental Tranche A Revolving Loan Commitments are available on a revolving basis, and such amounts that are repaid or prepaid may be re-borrowed. The loans issued pursuant to the Incremental Tranche A Revolving Loan Commitments bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate with respect to any Base Rate Loan, with steps down based on a Senior Secured Leverage Ratio (as such terms are defined in the Credit Agreement). Further on the Duke Midwest Closing Date, Dynegy entered into a Second Amendment to the Credit Agreement (the “Second Amendment”) among the Company, certain subsidiaries of Dynegy, the lenders party thereto, Credit Suisse, as administrative agent, and the other parties thereto. The Second Amendment provides for a new $600 million five -year senior secured incremental tranche of revolving commitments (the “Incremental Tranche B Revolving Loan Commitments”), which have terms substantially the same as the terms of the outstanding tranche of revolving loans under the Credit Agreement and will mature on April 2, 2020. Amounts available under the Incremental Tranche B Revolving Loan Commitments are available on a revolving basis, and such amounts that are repaid or prepaid may be re-borrowed. The loans issued pursuant to the Incremental Tranche B Revolving Loan Commitments bear interest, initially, at either (i) 2.75 percent per annum plus LIBOR with respect to any LIBOR Loan or (ii) 1.75 percent per annum plus the Base Rate with respect to any Base Rate Loan, with steps down based on a Senior Secured Leverage Ratio (as such terms are defined in the Credit Agreement). Subsequent to the First Amendment and Second Amendment, we have three tranches of revolvers: (i) $475 million tranche which will mature on April 23, 2018, (ii) $350 million tranche which will mature April 1, 2020 and (iii) $600 million tranche which will mature on April 2, 2020. Genco Senior Notes On December 2, 2013, in connection with the AER Acquisition, Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) remained outstanding as an obligation of Genco, a subsidiary of IPH. Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% __________________________________________ (1) As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. (2) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests. Genco’s debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness. Based on December 31, 2015 calculations, Genco’s interest coverage ratios are less than the minimum ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources. Letter of Credit Facilities On January 29, 2014, IPM entered into a fully cash collateralized Letter of Credit and Reimbursement Agreement with Union Bank, as amended on May 16, 2014 (“LC Agreement”), pursuant to which the issuing bank agreed to issue from time to time, one or more standby letters of credit in an aggregate stated amount not to exceed $25 million at any one time to support performance obligations and other general corporate activities of IPM, provided that IPM deposits in an account controlled by the issuing bank an amount of cash sufficient to cover the face value of such requested letter of credit plus an additional percentage thereon. As of December 31, 2015 , IPM had $23 million deposited with Union Bank and $20 million in letters of credit outstanding. On September 18, 2014, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, and its affiliate Macquarie Energy, LLC (the “Lender”), for a letter of credit in an amount not to exceed $55 million . The facility expires in May 2016. At December 31, 2015 , there was $55 million outstanding under this letter of credit. On March 27, 2015, IPM entered into a letter of credit facility with the Lender for up to $25 million . The facility, which is collateralized by receivables, has a two -year tenor and may be extended if agreed to by both parties for one additional year. Interest on the facility is LIBOR plus 500 basis points on issued letters of credit. At December 31, 2015 , there was $25 million outstanding under this letter of credit facility. 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. The Inventory Financing Agreement terminates, and any remaining obligation becomes due and payable, on May 31, 2017. As of December 31, 2015 , there was $58 million outstanding under this agreement. As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation cost, and other expenses. The debt obligation increases for 85 percent of the total price of the coal and 90 percent for the total price of fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil, respectively. Upon consuming the materials, we repay the debt obligation and line of credit at the then market price, as defined within the Inventory Financing Agreement, for the amount of the materials consumed on a weekly basis. As of December 31, 2015 , both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3 -month LIBOR plus 5.6 percent . An availability fee is calculated on a per annum rate of 0.75 percent . Emissions Repurchase Agreements. On August 14, 2015, we entered into a repurchase transaction with a third party in which we sold approximately $58 million of RGGI inventory and received cash. We are obligated to repurchase a portion of the inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.56 percent . On August 20, 2015, we entered into an additional repurchase transaction with a third party in which we sold $20 million of RGGI inventory and received cash. We are obligated to repurchase the additional RGGI inventory in February 2017 at a specified price with an annualized carry cost of approximately 3.31 percent . As of December 31, 2015 , there was $78 million , in aggregate, outstanding under these agreements. In 2013, we entered into two repurchase transactions in which we sold $6 million in California Carbon Allowances (“CCA”) credits and $11 million of RGGI inventory and received cash. In the first quarter 2014, we entered into an additional repurchase agreement with a third party in which we sold $12 million of RGGI inventory and received cash. In October 2014, we repurchased all $6 million of the previously sold CCA credits in February 2015, we repurchased all $23 million of the previously sold RGGI inventory. Equipment Financing Agreements Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to 2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our consolidated statements of cash flows. As of December 31, 2015 , there was $75 million outstanding under these agreements. The related assets were recorded at the net present value of the payments of $61 million . The $14 million discount is currently amortized as interest expense over the life of the payments. Interest Rate Swaps Subsequent to executing the Credit Agreement and issuing the Senior Notes, we amended our interest rate swaps to more closely match the terms of our Tranche B-2 Term Loan. The swaps have an aggregate notional value of approximately $777 million at an average fixed rate of 3.19 percent with a floor of one percent and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the new swaps are reflected as a financing activity in our consolidated statements of cash flows.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Note 14—Income Taxes Income Tax Benefit. We are subject to U.S. federal and state income taxes on our operations. Our losses from continuing operations before income taxes were $427 million , $268 million and $417 million for the years ended December 31, 2015 , 2014 and 2013, respectively, which was solely from domestic sources. Our components of income tax (expense) benefit related to income (loss) from continuing operations were as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Current tax expense $ (3 ) $ — $ (9 ) Deferred tax benefit 477 1 67 Income tax benefit $ 474 $ 1 $ 58 Our income tax benefit related to losses from continuing operations before income taxes for each of the years ended December 31, 2015, 2014 and 2013 were equivalent to effective rates of 111 percent , zero percent and 14 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) 2015 2014 2013 Expected tax benefit at U.S. statutory rate (35%) $ 149 $ 94 $ 146 State taxes 68 — 3 Permanent differences (1) 16 (15 ) 2 Valuation allowance (2)(3)(4) 271 (331 ) (22 ) Uncertain tax position — 244 (67 ) Unconsolidated subsidiary adjustment — 5 — Adjustment to AMT credits (26 ) — — Other (4 ) 4 (4 ) Income tax benefit $ 474 $ 1 $ 58 __________________________________________ (1) Permanent items for 2015 and 2014 included an $18 million benefit and $14 million expense, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. (2) The AER Acquisition in 2013 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $36 million reduction to our valuation allowance in connection with the AER Acquisition. In addition, 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. (3) Pre-tax income from components other than continuing operations provided a source of income that allowed for the reduction of the valuation allowance from continuing operations the year ended December 31, 2013. (4) On April 14, 2014, we received final notice from the Internal Revenue Service (“IRS”) that their audit of our 2012 tax year has been completed. In accordance with accounting guidance in ASC 740, Income Taxes (“ASC 740”), we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in the second quarter of 2014 as a discrete item with a corresponding adjustment to the valuation allowance. Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows: Year Ended December 31, (amounts in millions) 2015 2014 Current: Deferred tax assets: Reserves (legal, environmental and other) $ — $ 5 Intangible contracts and other — 44 Derivative contracts — 28 Other — 9 Subtotal — 86 Less: valuation allowance — (72 ) Total current deferred tax assets — 14 Deferred tax liabilities: Derivative contracts — (23 ) Other — (11 ) Total current deferred tax liabilities — (34 ) Net current deferred tax liabilities — (20 ) Non-current: Deferred tax assets: NOL carryforwards 1,533 1,305 AMT and state tax credit carryforwards 275 280 Reserves (legal, environmental and other) 17 6 Pension and other post-employment benefits 16 20 Asset retirement obligations 89 81 Deferred financing costs and intangible/other contracts 64 40 Derivative contracts 69 14 Other 27 14 Subtotal 2,090 1,760 Less: valuation allowance (1,276 ) (1,463 ) Total non-current deferred tax assets 814 297 Deferred tax liabilities: Depreciation and other property differences (738 ) (209 ) Deferred financing costs and power contracts — — Investment in unconsolidated partnership (27 ) — Derivative contracts (4 ) (14 ) Other (74 ) (54 ) Total non-current deferred tax liabilities (843 ) (277 ) Net non-current deferred tax assets (liabilities) (29 ) 20 Net deferred tax liability $ (29 ) $ — NOL Carryforwards. As of December 31, 2015 , we had approximately $3.9 billion of federal tax net operating loss carryforwards (“NOLs”) and $3.1 billion of state NOLs that can be used to offset future taxable income. The federal NOLs expire beginning in 2024 through 2035. Similarly, the state NOLs will expire at various dates (based on the company’s review of the application of apportionment factors and other state tax limitations). Under federal income tax law, our NOLs can be utilized to reduce future taxable income subject to certain limitations, including if we were to undergo an ownership change as defined by Internal Revenue Code (“IRC”) Section 382. If an ownership change were to occur as a result of future transactions in our stock, our ability to utilize the NOLs may be significantly limited. Alternative Minimum Tax Credit Carryforwards. While our Alternative Minimum Tax (“AMT”) credits do not expire, the change in control that occurred on May 9, 2012 materially impacted our ability to utilize the AMT credits. The Company filed an amended 2009 tax return on April 8, 2015, as permitted by the IRS, which allows the Company to utilize more AMT NOLs. This relief resulted in a reduction of AMT credits of $26 million . 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, 2015 , we have a valuation allowance against our net deferred assets including federal and state NOLs and AMT credit carryforwards. Additionally, at December 31, 2015 , 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: (amounts in millions) Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Additions/ (Deductions) Balance at End of Period Year Ended December 31, 2015 Changes in valuation allowance—continuing operations $ 1,535 (259 ) — — $ 1,276 Year Ended December 31, 2014 Changes in valuation allowance—continuing operations $ 1,149 370 16 — $ 1,535 Year Ended December 31, 2013 Changes in valuation allowance—continuing operations $ 1,121 28 — — $ 1,149 Unrecognized Tax Benefits. We are complete with federal income tax audits by the IRS through 2013 as a result of our participation in the IRS’ Compliance Assurance Process. However, any NOLs we claim in future years to reduce taxable income could be subject to additional IRS examination regardless of when the NOLs occurred. We are generally not subject to examinations for state and local taxes for tax years 2010 or earlier with few exceptions. On April 14, 2014, we received final notice from the IRS that their audit of our 2012 tax year was completed. In accordance with accounting guidance in ASC 740, we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in 2014 as a discrete item with a corresponding adjustment to the valuation allowance. A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: Year Ended December 31, amounts in millions 2015 2014 2013 Unrecognized tax benefits, beginning of period $ 4 $ 274 $ 1 Increase based on tax positions related to the prior period — — 273 Decrease due to settlements and payments (1 ) (270 ) — Unrecognized tax benefits, end of period $ 3 $ 4 $ 274 As of December 31, 2015 , approximately $3 million of unrecognized tax benefits would impact our effective tax rate if recognized.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	Note 15—Earnings (Loss) Per Share The reconciliation of basic earnings (loss) per share to diluted earnings (loss) per share from continuing operations attributable to our common stockholders during the years ended December 31, 2015, 2014 and 2013 is shown in the following table. Year Ended December 31, (in millions, except per share amounts) 2015 2014 2013 Income (loss) from continuing operations $ 47 $ (267 ) $ (359 ) Less: Net income (loss) attributable to noncontrolling interest (3 ) 6 — Income (loss) from continuing operations attributable to Dynegy Inc. 50 (273 ) (359 ) Less: Dividends on preferred stock 22 5 — Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted earnings (loss) per share $ 28 $ (278 ) $ (359 ) Basic weighted-average shares 125 105 100 Effect of dilutive securities (1) 1 — — Diluted weighted-average shares 126 105 100 Basic and diluted earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders (1) $ 0.22 $ (2.65 ) $ (3.59 ) __________________________________________ (1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2014 and 2013 . For the years ended December 31, 2015, 2014 and 2013 , the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive: Year Ended December 31, (in millions of shares) 2015 2014 2013 Stock options 0.5 1.4 1.0 Restricted stock units — 1.0 0.7 Performance stock units — 0.3 0.1 Warrants 15.6 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 4.0 — Total 29.0 22.3 17.4

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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, and nature of damages sought and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals and that such differences could be material. In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations or cash flows. Gas Index Pricing Litigation. We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. At this time we cannot reasonably estimate a potential loss. Illinova Generating Company Arbitration. In May 2007, our subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million , which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award. On May 23, 2014, the Texas Supreme Court vacated the arbitration award based upon the evident partiality of one of the arbitrators. On November 20, 2014, PPE initiated a new arbitration against IGC and its co-respondents, but the Dallas District Court enjoined the arbitration from proceeding against IGC while any dispute over IGC’s $17 million payment remains pending. On December 16, 2014, the Dallas District Court entered a judgment requiring the return of the $17 million to IGC and an additional $2.5 million payment to IGC for interest. PPE paid the $17 million principal to IGC (not the $2.5 million in interest), but simultaneously appealed the judgment, which remains pending in the Dallas Court of Appeals. Other Contingencies MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. Dynegy complied fully with the terms of the MISO Tariff in connection with the 2015-2016 PRA, disputes the allegations and will defend its actions vigorously. Dynegy filed its Answer to these complaints. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint. On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule or regulation. Further, FERC held a Staff-led technical conference on October 20, 2015 to obtain further information concerning potential changes to the MISO PRA structure going forward, including proposals made by complainants. The technical conference did not address the ongoing Office of Enforcement investigation. On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO Tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. Under the order, FERC found that the existing tariff provision which bases Initial Reference Levels for capacity supply offers on the estimated opportunity cost of exporting capacity to a neighboring region (for example, PJM) are no longer just and reasonable. Accordingly, FERC required MISO to set the Initial Reference Level for capacity at $0 per MW-day for the 2016-2017 PRA. Capacity suppliers may also request a facility-specific reference level from the MISO IMM. The order did not address the arguments of the complainants regarding the 2015-2016 Auction, and stated that those issues remain under consideration and will be addressed in a future order. New Source Review and Clean Air Act Matters. New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006 and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. If not overturned, this decision may provide an additional defense to the allegations in the Newton facility NOV. Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. We plan to retire our Wood River facility in mid-2016, subject to the approval of MISO. CAA Notices of Violation. In December 2014, the EPA issued a NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we co-own but do not operate. Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. The District Court has scheduled the trial date for October 2016. We dispute the allegations and will defend the case vigorously. Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters. Stuart NPDES Permit Appeal. In January 2013, the Ohio EPA reissued the National Pollutant Discharge Elimination System (“NPDES”) permit for the co-owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter. Coal Segment Groundwater . In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities. At Baldwin, with approval of the Illinois EPA, we performed a comprehensive evaluation of the Baldwin CCR surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the Illinois EPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. We await Illinois EPA action on our proposed action plan and recommendations. We initiated an investigation at Baldwin in 2011 at the request of the Illinois EPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the Illinois EPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. The cause of the exceedances is uncertain. At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the Illinois EPA in 2012. Our hydrogeologic investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the Illinois EPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await Illinois EPA action on our proposed corrective action plans. In June 2015, we advised the Illinois EPA that the additional analyses requested by the Agency would be performed upon receipt of a riverbank stabilization permit from the U.S. Army Corps of Engineers. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million . If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill. If remediation measures concerning groundwater are necessary at any of our IPH facilities, 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. Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments in 2009. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities. In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million , which is reflected in our ARO. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the Illinois EPA in 2014 and await Illinois EPA action. In response to the Baldwin report, we notified the EPA in 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs. Other Commitments In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, design and construction, plant sites, power generation assets and liquefied petroleum gas vessel charters. The following describes the more significant commitments outstanding at December 31, 2015 . Coal Purchase Commitments. At December 31, 2015 , we had contracts in place to purchase coal for our generation facilities with aggregate minimum commitments of $1.447 billion . To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar. Coal Transportation . At December 31, 2015 , we had coal transportation contracts and rail car leases in place for our generation facilities with aggregate minimum commitments of $904 million . Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obligations to purchase uprate equipment of $102 million through 2025. Recently we have undertaken several measures to restructure our existing maintenance agreements as well as negotiate new long-term maintenance service agreements with proven turbine service providers. The term of these agreements will be determined by the maintenance cycles of the respective facility. We currently estimate these agreements will be in effect for a period of 15 or more years. Either party can terminate the agreements based on certain events as specified in the contracts. As of December 31, 2015 , our minimum obligation with respect to these agreements is limited to the termination payments, which are approximately $356 million and $431 million in the event all contracts are terminated by us or the counterparty, respectively. Environmental Compliance Obligations. We estimate costs, excluding capitalized interest, of approximately $186 million for the completion of scheduled milestones related to the installation of the Newton facility scrubber systems, such that the IPH fleet will comply with certain SO 2 emission limits approved in the variance granted by the IPCB in November 2013. Please read Business - Environmental Matters - IPH Variance for further details. The first milestone relating to the engineering design was completed in July 2015, while the last milestone relates to major equipment components being placed into final position on or before September 1, 2019. We currently estimate this contract will be in effect for a period of four or more years. We are currently scheduled to complete the Newton scrubber project by the end of 2019 with minimal costs anticipated in 2020. Either party can terminate this contract based on certain events as specified in the contract. In February 2016, Genco issued a notice to the third party contractor constructing the scrubber systems directing them to temporarily suspend a portion of the work being performed. Gas Purchase Commitments. At December 31, 2015 , we had contracts in place to purchase gas for our generation facilities with aggregate minimum commitments of $254 million . Gas Transportation. At December 31, 2015 , 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 $205 million . Operating leases. Office Space, Equipment and Other Property. Minimum lease payment obligations, by year, associated with office space, equipment, land and other leases are $5 million per year for the years 2016-2020. During the years ended December 31, 2015, 2014 and 2013 , we recognized rental expense of approximately $5 million , $5 million and $6 million , respectively. Charter Agreements. The aggregate minimum base commitments of our charter party agreements are approximately $11 million for the year ended December 31, 2016. We are party to two charter agreements related to very large gas carriers (“VLGCs”) previously utilized in our former global liquids business. The primary term of one charter expired at the end of September 2013 but has been extended annually, through September 2016, at the option of the counterparty. The primary term of the second charter was through September 2014 but has been extended through September 2016 at the option of the counterparty. The first charter will terminate at the end of September 2016, and the second charter has an optional one -year extension remaining. Both of these VLGCs have been sub-chartered to a wholly-owned subsidiary of Transammonia Inc. on terms that are identical to the terms of the original charter agreements. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement and has not exercised the remaining optional extension. Other Obligations. We have other obligations of $48 million for contracts in place to purchase limestone, $23 million for interconnection services and $28 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. LS Power Indemnities. In connection with the 2009 transaction with LS Power, we agreed to indemnify LS Power against claims regarding any breaches in our representations and warranties and certain other potential liabilities. Even though Dynegy was discharged from any claims pursuant to the order confirming our Joint Chapter 11 Plan of Reorganization, effective October 1, 2012, (the “Plan”), Dynegy Power Generation Inc., Dynegy Power, LLC (“DPC”), Dynegy Midwest Generation, LLC (“DMG”) and Dynegy Power Marketing, LLC remain jointly and severally liable for any indemnification claims. Although certain of the indemnification obligations are indefinite, some are no longer in effect under the relevant transaction agreements or have exceeded the applicable statute of limitations. In addition, some of these indemnification obligations are subject to individual thresholds and/or maximum aggregate limits depending on the terms of the transaction agreement. We have accrued no amounts with respect to the indemnifications as of December 31, 2015 because none were probable of occurring, nor could they be reasonably estimated. EquiPower Acquisition. In connection with the ECP Purchase Agreements, the ECP Purchasers agreed to indemnify the ECP Sellers against claims regarding breaches in the covenants and representations and warranties of the ECP Purchasers and certain other potential liabilities. The indemnification obligations of the ECP Purchasers survive for one year for most covenants and representations and warranties of the ECP Purchasers, two years for fundamental representations and indefinitely for certain other matters. The ECP Sellers shall, in the aggregate, not be entitled to indemnification in excess of $276 million . We have accrued no amounts with respect to this indemnification as of December 31, 2015 . Please read Note 3—Acquisitions for further discussion. Duke Midwest Acquisition. In connection with the Duke Midwest Purchase Agreement, DRI agreed to indemnify Duke Energy against claims regarding breaches in the covenants and representations and warranties of DRI and certain other potential liabilities. The indemnification obligations of DRI survive for one year for most covenants and representations and warranties of DRI, three years for fundamental representations, 30 days after the applicable statute of limitations for certain tax matters, and indefinitely for certain other matters. We have accrued no amounts with respect to this indemnification as of December 31, 2015 . Dynegy has guaranteed, up to a maximum liability of $2.8 billion , the obligations of DRI under the Duke Midwest Purchase Agreement and related TSA. Please read Note 3—Acquisitions for further discussion.

Capital Stock

Capital Stock	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Capital Stock	Note 17—Capital Stock Preferred Stock We have authorized preferred stock consisting of 20 million shares, $0.01 par value. Our preferred stock may be issued from time to time in one or more series, the shares of each series to have such designations and powers, preferences, rights, qualifications, limitations and restrictions thereof as specified by our Board of Directors. As of December 31, 2015 , there were 4 million shares of our Series A Mandatory Convertible Preferred Stock (as described below) issued and outstanding. Series A Mandatory Convertible Preferred Stock. On October 14, 2014, we issued 4 million shares, $0.01 par value, pursuant to a registered public offering, of our 5.375% Series A Mandatory Convertible Preferred Stock (“Mandatory Convertible Preferred Stock”) at $100 per share, for gross proceeds of approximately $400 million , before underwriting discounts and commissions of $13 million (“Mandatory Convertible Preferred Stock Offering”). These issuance costs are included in Additional paid-in capital on our consolidated balance sheets. The underwriters in the Mandatory Convertible Preferred Stock Offering had an option for 30 days to purchase an additional 0.6 million shares of our Mandatory Convertible Preferred Stock at $100 per share; however, the option was not exercised. The Mandatory Convertible Preferred Stock has a liquidation preference of $100 per share, or an aggregate preference of $400 million . Dividends accrue at 5.375 percent per annum on the liquidation preference and will be payable on a cumulative basis when and if declared by our Board of Directors. We may pay declared dividends in cash or, subject to certain limitations, in shares of our common stock or by delivery of any combination of cash and shares of our common stock on February 1, May 1, August 1 and November 1 of each year, commencing on February 1, 2015, and to, and including, November 1, 2017. On January 15, 2015, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.64 per share, or approximately $7 million in the aggregate. The dividend is for the initial dividend period beginning on October 14, 2014 and ending on January 31, 2015. Such dividends were paid on February 2, 2015 to stockholders of record as of January 15, 2015. On March 3, 2015, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million . An equivalent dividend was also declared on July 1, 2015, October 2, 2015 and January 5, 2016. Such dividends were paid on May 1, 2015, August 3, 2015, November 2, 2015 and February 1, 2016, respectively. As long as we are not in default on our credit agreements, we are not restricted from paying dividends on the Mandatory Convertible Preferred Stock. During the year ended December 31, 2015 , we paid an aggregate of $23 million in dividends. We paid no dividends during 2014. At any time prior to November 1, 2017, other than during a Fundamental Change Conversion Period (as defined in the Certificate of Designations for the Mandatory Convertible Preferred Stock (the “Certificate of Designations”)), holders of the Mandatory Convertible Preferred Stock have the right to elect to convert their shares in whole or in part at the Minimum Conversion Rate of 2.5806 shares of our common stock per share of Mandatory Convertible Preferred Stock. This Minimum Conversion Rate is subject to certain anti-dilution adjustments. The Certificate of Designations provides that during a Fundamental Change Conversion Period, the shares may be converted by the holder at the Fundamental Change Conversion Rate, as defined therein. Each share of Mandatory Convertible Preferred Stock will, unless previously converted, automatically convert on November 1, 2017, into between 2.5806 and 3.2258 shares of our common stock, subject to anti-dilution and other adjustments. The Mandatory Convertible Preferred Stock is not redeemable by us. The holders of the Mandatory Convertible Preferred Stock generally have no voting rights except in the case of dividend arrearages. Holders are not entitled to participate in any dividends which may be declared and paid on our common stock. 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 approximately 100 million shares were issued in the aggregate and no shares were held in treasury. On October 14, 2014, we issued 22.5 million shares, pursuant to a registered public offering, of our common stock at $31.00 per share (“Common Stock Offering”). On November 13, 2014, we issued an additional 1.5 million shares, pursuant to the exercise by the underwriters of their 30 day option to purchase up to 3.375 million additional shares of our common stock, at $31.00 per share. The aggregate gross proceeds received by Dynegy from the Common Stock Offering were approximately $744 million , before underwriting discounts and commissions of $38 million , which are recorded on a net basis and included in Additional paid-in capital on our consolidated balance sheets. During the year ended December 31, 2015 , no quarterly cash dividends related to our common stock were paid by us. On April 1, 2015, pursuant to the ERC Purchase Agreement, 3,460,053 shares of common stock of Dynegy valued at approximately $105 million were issued as part of the consideration for the EquiPower Acquisition, before related financing costs of approximately $6 million , which is recorded on a net basis and included in Additional paid-in capital on our consolidated balance sheets. The value of the common stock issued was based on the closing price of Dynegy’s common stock on the EquiPower Closing Date. Please read Note 3—Acquisitions for further discussion. On August 3, 2015, our Board of Directors authorized a share repurchase program for up to $250 million , which was initiated in the third quarter of 2015 and completed in the fourth quarter of 2015. The shares were purchased in the open market or in privately negotiated transactions at prevailing market prices. As of December 31, 2015 , we repurchased 11,326,122 shares at an aggregate cost of $250 million . As of the Plan Effective Date, we issued to Legacy Dynegy stockholders warrants to purchase up to 15.6 million shares of common stock for an exercise price of $40 per share (the “Warrants”). The Warrants have a five -year term expiring on October 2, 2017 . The exercise price of the Warrants and the number of shares issuable upon exercise of the Warrants are subject to adjustment upon certain events including: stock subdivisions, combinations, splits, stock dividends, capital reorganizations or capital reclassifications of common stock. Further, in connection with Subject Transactions (as defined in the Warrant Agreement), warrant holders are entitled to certain distributions. If the value of the Warrants is underwater upon the determination date of a Subject Transaction, such distributions are equivalent to $0.01 per warrant, or approximately $150 thousand for all Warrants outstanding. As a result of this potential distribution, the Warrants are classified as a liability in our consolidated financial statements and are adjusted to their estimated fair value at the end of each reporting period with the change in fair value recognized in Other income (expense) on our consolidated statement of operations. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion. Stock Award Plans We have one stock award plan, the Dynegy 2012 Long Term Incentive Plan (the “2012 LTIP”), which provides for the issuance of authorized shares of our common stock. Restricted Stock Units (“RSUs”), Performance Stock Units (“PSUs”) and option grants were issued under the 2012 LTIP following the Plan Effective Date. Each option granted is exercisable at a strike price, which ranges from $18.70 per share to $32.56 per share for options currently outstanding as of December 31, 2015 . The 2012 LTIP is a broad-based plan and provides for the issuance of approximately 6.1 million authorized shares through October 2022 . The maximum number of shares of common stock that may be subject to options, restricted stock awards, stock unit awards, stock appreciation rights, phantom stock awards and performance awards, denominated in shares of common stock granted to any one individual during any calendar year may not exceed approximately 1.2 million shares or the equivalent of approximately 1.2 million shares of common stock (subject to adjustment in accordance with the provisions of the 2012 LTIP). The maximum amount of compensation that may be paid under all performance awards denominated in cash (including the fair market value of any shares of common stock paid in satisfaction of such performance awards) granted to any one individual during any calendar year may not exceed a fair market value of $10 million . Any options granted under the 2012 LTIP will expire no later than 10 years from the date of the grant. All options granted under the 2012 LTIP cease vesting for employees who are terminated with cause. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate or continued vesting and/or an extended period in which to exercise vested options may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon exercise of stock options from previously unissued shares. All RSUs granted under the 2012 LTIP contain a service condition and cease vesting for employees or directors who are terminated with cause. For severance-eligible employee terminations, as defined under the severance pay plan, director terminations without cause, employee or director disability, retirement or death, immediate vesting of some or all of the RSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Shares of common stock are issued upon vesting of RSUs from previously unissued shares. All PSUs granted under the 2012 LTIP contain a performance condition and cease vesting for employees who do not remain continuously employed during the performance period under the grant agreements. For severance-eligible terminations, as defined under the severance pay plan, disability, retirement or death, immediate vesting of some or all of the PSUs may apply, dependent upon the terms of the grant agreement applying to a specific grant that was awarded. Upon a corporate change, employees receive an immediate vesting of PSUs regardless of whether the employee is terminated. We use the fair value based method of accounting for stock-based employee compensation. Compensation expense related to options, RSUs and PSUs granted totaled $28 million , $19 million and $15 million for the years ended December 31, 2015, 2014 and 2013 , 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 $10 million , $7 million and $5 million for the years ended December 31, 2015, 2014 and 2013 , respectively. As of December 31, 2015 , $25 million of total unrecognized compensation expense related to options, RSUs and PSUs granted is expected to be recognized over a weighted-average period of 2.5 years. The total fair value of options, RSUs and PSUs vested was $18 million , $14 million and $5 million for the years ended December 31, 2015, 2014 and 2013 , respectively. We did not capitalize or use cash to settle any share-based compensation in the years ended December 31, 2015, 2014 and 2013 . Cash received from option exercises for the years ended December 31, 2015, 2014 and 2013 was $0.5 million , $1 million and $2 million , respectively, and the tax benefit realized for the additional tax deduction from share-based payment awards totaled less than $1 million for the years ended December 31, 2015, 2014 and 2013 . The following summarizes our stock option activity: Year Ended December 31, 2015 Options (in thousands) Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in years) Aggregate Intrinsic Value Outstanding at beginning of period 1,372 $ 21.15 Granted 485 $ 27.43 Exercised (25 ) $ 20.93 Outstanding at end of period 1,832 $ 22.81 8.54 $ — Vested and unvested expected to vest 1,832 $ 22.81 8.54 $ — Exercisable at end of period 945 $ 20.38 7.27 $ — During the years ended December 31, 2015, 2014 and 2013 , 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, 2014 and 2013 was $23.03 and $22.84 , respectively. The intrinsic value of options exercised during the years ended December 31, 2015, 2014 and 2013 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, 2015 2014 2013 Dividend Yield $ — $ — $ — Expected volatility (1) 27.70 % 23.96 % 32.79 % Risk-free interest rate (2) 1.64 % 1.61 % 1.05 % Expected option life (3) 5.5 years 5.5 years 5.5 years __________________________________________ (1) For the years ended December 31, 2015 and 2014 , the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012. For the year ended December 31, 2013, the expected volatility was calculated based on five -year historical volatilities of the stock of comparable companies whose shares are traded using daily stock price returns equivalent to the expected term of the options. (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 weighted average grant-date fair value of options granted during the years ended December 31, 2015, 2014 and 2013 was $7.93 , $5.91 and $7.35 , respectively. The following summarizes our RSU activity: Year Ended December 31, 2015 RSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 1,046 $ 22.94 Granted 878 $ 28.93 Vested and released (468 ) $ 22.53 Forfeited (43 ) $ 25.83 Outstanding at end of period 1,413 $ 26.71 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, 2014 and 2013 was $23.36 and $23.15 , 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, 2015 PSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 304 $ 23.13 Granted 278 $ 27.54 Vested and released — $ — Forfeited (6 ) $ 27.07 Outstanding at end of period 576 $ 25.22 The weighted average grant date fair value of PSUs granted during the years ended December 31, 2014 and 2013 was $23.03 and $23.10 . The fair value of PSUs 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, 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.

Employee Compensation, Savings,

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Employee Compensation, Savings, Pension Other Post-Employment Benefit Plans	Note 18—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, 2015, 2014 and 2013 , our contributions related to these plans were approximately $50 million , $37 million and $28 million , respectively. The following summarizes these plans: Short-Term Incentive Plan. Dynegy maintains a discretionary incentive compensation plan to provide our employees with rewards for the achievement of corporate goals and individual, professional accomplishments. Specific awards are determined by Dynegy’s Compensation and Human Resources Committee of the Board of Directors and are based on predetermined goals and objectives established at the start of each performance year. Phantom Stock Plan. Dynegy has issued phantom stock units under its 2009 Phantom Stock Plan. Units awarded under this plan are long term incentive awards that grant the participant the right to receive a cash payment based on the fair market value of Dynegy’s stock on the vesting date of the award. As these awards must be settled in cash, we account for them as liabilities, with changes in the fair value of the liability recognized as expense in our consolidated statements of operations. Expense recognized in connection with these awards during the years ended December 31, 2015, 2014 and 2013 was $1 million , $4 million and $5 million , respectively. Dynegy Inc. 401(k) Savings Plans. For the years ended December 31, 2015, 2014 and 2013 , 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. The following summarizes the plans: • 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. Effective December 2, 2013, IPH employees participate in this plan and effective January 1, 2014, EEI employees participate in this plan. 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, 2015 . • EquiPower 401(k) Plans . As part of the EquiPower transaction, we acquired various 401(k) plans set forth below. Through December 31, 2015, these plans provided benefits to the former EquiPower and Brayton Point represented and non-represented employees. 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. • Kincaid Energy Services Company, LLC 401(k) Plan • Kincaid Energy Services Company, LLC 401(k) Plan for Bargaining Employees • Brayton Point Energy LLC 401k Plan • Brayton Point Energy LLC 401k Plan for Bargaining Employees • Elwood Services Company LLC 401k Plan • EquiPower Resources Corp. 401k Plan • Kincaid Energy Services Company LLC 401k Plan • Kincaid Energy Services Company LLC 401k Plan for Bargaining Employees During the years ended December 31, 2015, 2014 and 2013 , we recognized aggregate costs related to these employee compensation plans of $10 million , $7 million and $4 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 2013, we recognized a curtailment loss of $1 million related to EEI’s other post-employment plan for EEI salaried employees, resulting from a plan amendment and terminations associated with the AER Acquisition and a curtailment gain of $7 million in connection with the termination of a majority of the Danskammer, L.L.C. (“Danskammer”) employees and the sale of our Dynegy Roseton, L.L.C. (“Roseton”) facility. In addition, we also reached an agreement with the union representing employees of the facility. As a result of these amendments to certain pension and other post-employment benefit plans, we remeasured our benefit obligations and the funded status of the affected plans in 2013. Upon the close of the Duke Midwest Acquisition on April 2, 2015, we assumed certain benefit plan obligations and the associated plan assets were transferred to us. These benefit plan obligations and related plan assets were merged into our pension and other post-employment benefit plans. The Duke employees began participating in our plans upon acquisition, which as a result triggered a remeasurement of our plans during the second quarter of 2015. No pension obligations associated with the EquiPower employees were assumed upon the EquiPower Acquisition on April 1, 2015. Effective January 1, 2016, EquiPower employees were eligible to participate in our plan, except for employees that were in the Brayton Point Energy LLC 401k Plan for Bargaining Employees as it was not merged into our plan. In August 2015, we finalized certain new collective bargaining agreements that resulted in amendments to certain pension and other post-employment benefit plans. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans during the third quarter of 2015. Obligations and Funded Status. The following tables contain information about the obligations, plan assets and funded status of plans in which we, or one of our subsidiaries, formerly sponsored or participated in on a combined basis. These amounts include the obligations, plan assets and funded status of EEI’s pension and post-employment plans. Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Benefit obligation, beginning of the year $ 408 $ 390 $ 95 $ 81 Service cost 14 12 1 1 Interest cost 18 17 4 4 Actuarial (gain) loss (20 ) 40 (12 ) 15 Benefits paid (26 ) (37 ) (5 ) (6 ) Plan change — — (10 ) — Settlements — (14 ) (1 ) — Duke Midwest Acquisition 89 — 2 — Benefit obligation, end of the year $ 483 $ 408 $ 74 $ 95 Fair value of plan assets, beginning of the year $ 364 $ 373 $ 68 $ 67 Actual return on plan assets (13 ) 39 2 5 Employer contributions 4 3 — — Benefits paid (26 ) (37 ) (3 ) (4 ) Settlements — (14 ) — — Duke Midwest Acquisition 81 — — — Fair value of plan assets, end of the year $ 410 $ 364 $ 67 $ 68 Funded status $ (73 ) $ (44 ) $ (7 ) $ (27 ) Our accumulated benefit obligation related to pension plans was $481 million and $408 million as of December 31, 2015 and 2014 , respectively. Our accumulated benefit obligation related to other post-employment plans was $74 million and $95 million as of December 31, 2015 and 2014 , respectively. Amounts recognized in the consolidated balance sheets consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Non-current assets $ 5 $ 1 $ 23 $ 15 Current liabilities — — (2 ) (2 ) Non-current liabilities (78 ) (45 ) (28 ) (40 ) Net amount recognized $ (73 ) $ (44 ) $ (7 ) $ (27 ) Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Prior service credit $ (11 ) $ (12 ) $ (34 ) $ (27 ) Actuarial loss (gain) (6 ) (21 ) 2 12 Net gain recognized $ (17 ) $ (33 ) $ (32 ) $ (15 ) 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, 2015, 2014 and 2013 for the defined benefit pension plans were $1 million , $2 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, 2015, 2014 and 2013 for other post-employment benefit plans was $3 million , $3 million and $1 million , respectively. The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2016 are as follows: (amounts in millions) Pension Benefits Other Benefits Prior service credit $ (1 ) $ (4 ) Actuarial (gain) loss — — Net gain recognized $ (1 ) $ (4 ) 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) 2015 2014 2013 Service cost benefits earned during period $ 14 $ 12 $ 9 Interest cost on projected benefit obligation 18 17 14 Expected return on plan assets (23 ) (21 ) (19 ) Amortization of: Prior service credit (1 ) (1 ) (1 ) Actuarial gain — (1 ) — Net periodic benefit cost 8 6 3 Curtailment gain (1) — — (7 ) Total benefit cost (gain) $ 8 $ 6 $ (4 ) __________________________________________ (1) The curtailment gain was related to the DNE pension plan and resulted from the Roseton sale and the termination of a majority of the Danskammer employees. Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost benefits earned during period $ 1 $ 1 $ 1 Interest cost on projected benefit obligation 4 4 2 Expected return on plan assets (4 ) (4 ) — Amortization of: Prior service credit (3 ) (3 ) (1 ) Net periodic benefit cost (gain) (2 ) (2 ) 2 Curtailment loss (1) — — 1 Total benefit cost (gain) $ (2 ) $ (2 ) $ 3 __________________________________________ (1) The curtailment loss for the year ended December 31, 2013 was related to EEI’s other post-employment plan for EEI salaried employees, resulting from a plan amendment and terminations associated with the AER Acquisition. Assumptions. The following weighted average assumptions were used to determine benefit obligations: Pension Benefits Other Benefits Year Ended December 31, 2015 2014 2015 2014 Discount rate (1) 4.35 % 4.00 % 4.35 % 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, 2015 2014 2013 2015 2014 2013 Discount rate 4.35 % 4.00 % 4.82 % 4.35 % 4.00 % 4.78 % Dynegy - Expected return on plan assets 5.70 % 6.00 % 7.00 % N/A N/A N/A EEI - Expected return on plan assets (1) 6.00 % 6.25 % 6.25 % 5.50 % 6.00 % 6.00 % Rate of compensation increase (2) 3.50 % 3.50 % 3.50 % 3.50 % 3.50 % 3.50 % __________________________________________ (1) The average expected return on EEI’s other post-employment plan assets was 5.50 percent for the year ended December 31, 2015 and 6 percent for the years ended December 31, 2014 and 2013 . The expected return on EEI’s other post-employment plan assets was 6.20 percent for EEI union employees and 4.80 percent for EEI salaried employees for the year ended December 31, 2015 . For the years ended December 31, 2014 and 2013 , the expected return on EEI’s other post-employment plan assets was 6.50 percent for EEI union employees and 5.50 percent for EEI salaried employees. (2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2015, 2014 and 2013 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 5.90 percent , respectively, for the year ended December 31, 2016. Our expected long-term rate of return on EEI’s other post-employment plan assets is 6.30 percent for EEI union employees and 5.75 percent for EEI salaried employees for the year ended December 31, 2016. 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, 2015 2014 2013 Health care cost trend rate assumed for next year 7.00 % 7.25 % 7.75 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2023 2023 2023 Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. The impact of a one percent increase/decrease in assumed health care cost trend rates is as follows: (amounts in millions) Increase Decrease Aggregate impact on service cost and interest cost $ 1 $ — Impact on accumulated post-employment benefit obligation $ 9 $ (7 ) 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 recently adopted a glide-path approach to de-risk the portfolio as funding levels increased. The target allocations for equity and fixed income investments have changed throughout 2015 and the asset mix as of December 31, 2015 was approximately 46 percent to equity investments and approximately 54 percent to fixed income investments. The target asset mix for EEI’s plan assets as of December 31, 2015 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, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 1 $ 1 $ — $ 2 Equity securities: U.S. companies (1) 32 125 — 157 Non-U.S. companies (2) — 10 — 10 International (3) 8 54 — 62 Fixed income securities (4) 83 152 — 235 Trust asset receivable (5) — 11 — 11 Total $ 124 $ 353 $ — $ 477 Fair Value as of December 31, 2014 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 2 $ — $ 2 Equity securities: U.S. companies (1) 7 142 — 149 Non-U.S. companies (2) — 11 — 11 International (3) 2 53 — 55 Fixed income securities (4) 81 134 — 215 Total $ 90 $ 342 $ — $ 432 ________________________________________ (1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market. (2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index. (3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index. (4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds. (5) Relates to the pension and other post-employment plans transferred to Dynegy as a result of the Acquisitions. Contributions and Payments. We were required to make contributions of $4 million and $3 million to our pension plans and no contributions to our other post-employment benefit plans during the years ended December 31, 2015 and 2014, respectively. We are required to make contributions of $2 million to our other post-employment benefit plans and no contributions to our pension plans during 2016. 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 2016 $ 36 $ 4 2017 $ 36 $ 4 2018 $ 36 $ 4 2019 $ 35 $ 4 2020 $ 36 $ 4 2021 - 2025 $ 183 $ 22

Quarterly Financial Information

Quarterly Financial Information	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Information	Note 19—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 2015 (1) Revenues $ 632 $ 990 $ 1,232 $ 1,016 Operating income (loss) (2) $ (40 ) $ 10 $ 107 $ (13 ) Net income (loss) $ (181 ) $ 386 $ (24 ) $ (134 ) Net income (loss) attributable to Dynegy Inc. common stockholders $ (185 ) $ 382 $ (29 ) $ (140 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic $ (1.49 ) $ 2.98 $ (0.23 ) $ (1.18 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted $ (1.49 ) $ 2.73 $ (0.23 ) $ (1.18 ) 2014 Revenues $ 762 $ 521 $ 615 $ 599 Operating income (loss) $ 1 $ (54 ) $ 22 $ 12 Net loss $ (37 ) $ (122 ) $ (5 ) $ (103 ) Net loss attributable to Dynegy Inc. common stockholders $ (41 ) $ (123 ) $ (5 ) $ (109 ) Net loss per share attributable to Dynegy Inc. common stockholders—Basic and diluted $ (0.41 ) $ (1.23 ) $ (0.05 ) $ (0.91 ) _____________________ (1) The unaudited quarterly information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 reflect the impact of the Acquisitions. Please read Note 3—Acquisitions for further discussion. (2) The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million , respectively. See Note 9—Property, Plant and Equipment for more information.

Condensed Consolidating Financi

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Financial Information	Note 20—Condensed Consolidating Financial Information On May 20, 2013, Dynegy issued the Senior Notes as further described in Note 13—Debt . On October 27, 2014, the Escrow Issuers, wholly-owned subsidiaries of Dynegy, issued the Notes as further described in Note 13—Debt . The 100 percent owned Subsidiary Guarantors, jointly, severally and unconditionally, guaranteed the payment obligations under the Senior Notes and the Notes. Not all of Dynegy’s subsidiaries guarantee the Senior Notes and the Notes including Dynegy’s indirect, wholly-owned subsidiary, IPH, which acquired AER and its subsidiaries on December 2, 2013. The following condensed consolidating financial statements present the financial information of (i) Dynegy (Parent), which is the parent and issuer of the Senior Notes, on a stand-alone, unconsolidated basis, (ii) Escrow Issuers, which are the finance company issuers of the Notes, (iii) the guarantor subsidiaries of Dynegy, (iv) the non-guarantor subsidiaries of Dynegy and (v) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Dynegy. The condensed consolidating financial statements have been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. For purposes of the 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, 2015 and December 31, 2014. Condensed Consolidating Balance Sheet for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 327 $ 94 $ 84 $ — $ 505 Restricted cash — — 39 — 39 Accounts receivable, net 499 1,503 130 (1,730 ) 402 Inventory — 331 266 — 597 Other current assets 26 335 55 (14 ) 402 Total Current Assets 852 2,263 574 (1,744 ) 1,945 Property, Plant and Equipment, Net — 7,813 534 — 8,347 Other Assets Investment in affiliates 13,017 190 — (13,017 ) 190 Other long-term assets 77 133 50 — 260 Goodwill — 797 — — 797 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,963 $ 11,196 $ 1,158 $ (14,778 ) $ 11,539 Current Liabilities Accounts payable $ 1,388 $ 238 $ 396 $ (1,730 ) $ 292 Other current liabilities 95 277 162 (14 ) 520 Total Current Liabilities 1,483 515 558 (1,744 ) 812 Long-term debt 6,370 122 714 — 7,206 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 11,042 954 1,427 (4,803 ) 8,620 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,963 $ 11,196 $ 1,158 $ (14,778 ) $ 11,539 Condensed Consolidating Balance Sheet for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 1,642 $ — $ 54 $ 174 $ — $ 1,870 Restricted cash — 113 — — — 113 Accounts receivable, net 14 — 672 176 (592 ) 270 Inventory — — 88 120 — 208 Other current assets 9 6 125 73 — 213 Total Current Assets 1,665 119 939 543 (592 ) 2,674 Property, Plant and Equipment, Net — — 2,812 443 — 3,255 Other Assets Investment in affiliates 6,133 — — — (6,133 ) — Restricted cash — 5,100 — — — 5,100 Other long-term assets 46 47 53 57 — 203 Intercompany interest receivable 17 — — — (17 ) — Total Assets $ 7,861 $ 5,266 $ 3,804 $ 1,043 $ (6,742 ) $ 11,232 Current Liabilities Accounts payable $ 310 $ 166 $ 112 $ 220 $ (592 ) $ 216 Other current liabilities 51 67 250 97 — 465 Total Current Liabilities 361 233 362 317 (592 ) 681 Long-term debt 1,277 5,100 — 698 — 7,075 Intercompany note payable 3,042 — — 17 (3,059 ) — Other long-term liabilities 158 — 105 190 — 453 Total Liabilities 4,838 5,333 467 1,222 (3,651 ) 8,209 Stockholders’ Equity Dynegy Stockholders’ Equity 3,023 (67 ) 6,379 (179 ) (6,133 ) 3,023 Intercompany note receivable — — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 3,023 (67 ) 3,337 (179 ) (3,091 ) 3,023 Noncontrolling interest — — — — — — Total Equity 3,023 (67 ) 3,337 (179 ) (3,091 ) 3,023 Total Liabilities and Equity $ 7,861 $ 5,266 $ 3,804 $ 1,043 $ (6,742 ) $ 11,232 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,979 $ 895 $ (4 ) $ 3,870 Cost of sales, excluding depreciation expense — (1,485 ) (547 ) 4 (2,028 ) Gross margin — 1,494 348 — 1,842 Operating and maintenance expense — (570 ) (269 ) — (839 ) Depreciation expense — (500 ) (87 ) — (587 ) Impairments — (74 ) (25 ) — (99 ) Gain on sale of assets, net — (1 ) — — (1 ) General and administrative expense (6 ) (91 ) (31 ) — (128 ) Acquisition and integration costs — (124 ) — — (124 ) Operating income (loss) (6 ) 134 (64 ) — 64 Earnings from unconsolidated investments — 1 — — 1 Equity in earnings from investments in affiliates 476 — — (476 ) — Interest expense (475 ) (1 ) (70 ) — (546 ) Other income and expense, net 55 (1 ) — — 54 Income (loss) before income taxes 50 133 (134 ) (476 ) (427 ) Income tax benefit (Note 14) — 471 3 — 474 Net income (loss) 50 604 (131 ) (476 ) 47 Less: Net loss attributable to noncontrolling interest — — (3 ) — (3 ) Net income (loss) attributable to Dynegy Inc. $ 50 $ 604 $ (128 ) $ (476 ) $ 50 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ — $ 1,651 $ 846 $ — $ 2,497 Cost of sales, excluding depreciation expense — — (1,065 ) (596 ) — (1,661 ) Gross margin — — 586 250 — 836 Operating and maintenance expense — — (279 ) (198 ) — (477 ) Depreciation expense — — (210 ) (37 ) — (247 ) Gain on sale of assets, net — — 18 — — 18 General and administrative expense (9 ) — (60 ) (45 ) — (114 ) Acquisition and integration costs — — — (35 ) — (35 ) Operating income (loss) (9 ) — 55 (65 ) — (19 ) Bankruptcy reorganization items, net 3 — — — — 3 Earnings from unconsolidated investments — — 10 — — 10 Equity in losses from investments in affiliates (131 ) — — — 131 — Interest expense (89 ) (67 ) — (68 ) 1 (223 ) Other income and expense, net (39 ) — 1 — (1 ) (39 ) Income (loss) before income taxes (265 ) (67 ) 66 (133 ) 131 (268 ) Income tax benefit (expense) (Note 14) (8 ) — — 9 — 1 Net income (loss) (273 ) (67 ) 66 (124 ) 131 (267 ) Less: Net income attributable to noncontrolling interest — — — 6 — 6 Net income (loss) attributable to Dynegy Inc. $ (273 ) $ (67 ) $ 66 $ (130 ) $ 131 $ (273 ) Condensed Consolidating Statements of Operations for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 1,398 $ 68 $ — $ 1,466 Cost of sales, excluding depreciation expense — (1,099 ) (46 ) — (1,145 ) Gross margin — 299 22 — 321 Operating and maintenance expense — (293 ) (15 ) — (308 ) Depreciation expense — (213 ) (3 ) — (216 ) Gain on sale of assets, net — 2 — — 2 General and administrative expense (5 ) (90 ) (2 ) — (97 ) Acquisition and integration costs — — (20 ) — (20 ) Operating loss (5 ) (295 ) (18 ) — (318 ) Bankruptcy reorganization items, net — — — — — Earnings from unconsolidated investments — 2 — — 2 Equity in losses from investments in affiliates (315 ) — — 315 — Interest expense (56 ) (36 ) (5 ) — (97 ) Loss on extinguishment of debt (8 ) (3 ) — — (11 ) Other income and expense, net 4 3 — — 7 Loss from continuing operations before income taxes (380 ) (329 ) (23 ) 315 (417 ) Income tax benefit (expense) (Note 14) 21 58 (21 ) — 58 Loss from continuing operations (359 ) (271 ) (44 ) 315 (359 ) Income (loss) from discontinued operations, net of tax (Note 21) 3 (2 ) — 2 3 Net loss (356 ) (273 ) (44 ) 317 (356 ) Less: Net income (loss) attributable to noncontrolling interest — — — — — Net (loss) attributable to Dynegy Inc. $ (356 ) $ (273 ) $ (44 ) $ 317 $ (356 ) 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 $ 604 $ (131 ) $ (476 ) $ 47 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of zero (8 ) 2 10 — 4 Amounts reclassified from accumulated other comprehensive income (loss): Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (3 ) — (1 ) — (4 ) Other comprehensive income from investment in affiliates 11 — — (11 ) — Other comprehensive income, net of tax — 2 9 (11 ) — Comprehensive income (loss) 50 606 (122 ) (487 ) 47 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 — (2 ) (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 49 $ 606 $ (120 ) $ (486 ) $ 49 Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (273 ) $ (67 ) $ 66 $ (124 ) $ 131 $ (267 ) Other comprehensive income before reclassifications: Actuarial loss and plan amendments, net of zero tax expense (20 ) — — (16 ) — (36 ) Amounts reclassified from accumulated other comprehensive income (loss): Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense (5 ) — — — — (5 ) Other comprehensive loss from investment in affiliates (16 ) — — — 16 — Other comprehensive loss, net of tax (41 ) — — (16 ) 16 (41 ) Comprehensive income (loss) (314 ) (67 ) 66 (140 ) 147 (308 ) Less: comprehensive income attributable to noncontrolling interest 3 — — 3 (3 ) 3 Total comprehensive income (loss) attributable to Dynegy Inc. $ (317 ) $ (67 ) $ 66 $ (143 ) $ 150 $ (311 ) Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (356 ) $ (273 ) $ (44 ) $ 317 $ (356 ) Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of $31 tax expense 53 — 4 — 57 Amounts reclassified from accumulated other comprehensive income (loss): Reclassification of curtailment gain included in net loss, net of tax (7 ) — — — (7 ) Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense (2 ) — — — (2 ) Other comprehensive income from investment in affiliates 4 — — (4 ) — Other comprehensive income, net of tax 48 — 4 (4 ) 48 Comprehensive loss (308 ) (273 ) (40 ) 313 (308 ) Less: comprehensive income attributable to noncontrolling interest 1 — 1 (1 ) 1 Total comprehensive loss attributable to Dynegy Inc. $ (309 ) $ (273 ) $ (41 ) $ 314 $ (309 ) 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 $ (352 ) $ 574 $ (128 ) $ — $ 94 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (13 ) (199 ) (63 ) — (275 ) Decrease in restricted cash 5,148 — — — 5,148 Acquisitions (6,207 ) 29 100 — (6,078 ) Net intercompany transfers 448 — — (448 ) — Distributions from unconsolidated affiliates — 8 — — 8 Other investing — 3 — — 3 Net cash provided by (used in) investing activities (624 ) (159 ) 37 (448 ) (1,194 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of financing costs — 78 19 — 97 Repayments of borrowings (8 ) (23 ) — — (31 ) Financing costs from debt issuances (31 ) — — — (31 ) Financing costs from equity issuances (6 ) — — — (6 ) Dividends paid (23 ) — — — (23 ) Net intercompany transfers — (430 ) (18 ) 448 — Interest rate swap settlement payments (17 ) — — — (17 ) Repurchase of common stock (250 ) — — — (250 ) Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (339 ) (375 ) 1 448 (265 ) Net increase (decrease) in cash and cash equivalents (1,315 ) 40 (90 ) — (1,365 ) Cash and cash equivalents, beginning of period 1,642 54 174 — 1,870 Cash and cash equivalents, end of period $ 327 $ 94 $ 84 $ — $ 505 Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (70 ) $ (62 ) $ 353 $ (58 ) $ — $ 163 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — — (87 ) (45 ) — (132 ) Proceeds from sales of assets, net — — 18 — — 18 Increase in restricted cash — (5,148 ) — — — (5,148 ) Net intercompany transfers 162 — — — (162 ) — Net cash provided by (used in) investing activities 162 (5,148 ) (69 ) (45 ) (162 ) (5,262 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of preferred stock 400 — — — — 400 Proceeds from issuance of common stock 744 — — — — 744 Proceeds from long-term borrowings — 5,100 12 — — 5,112 Repayments of borrowings (8 ) — (6 ) — — (14 ) Financing costs from debt issuances (1 ) (56 ) — — — (57 ) Financing costs from equity issuances (38 ) — — — — (38 ) Interest rate swap settlement payments (18 ) — — — — (18 ) Net intercompany transfers — 166 (390 ) 62 162 — Other financing (3 ) — — — — (3 ) Net cash provided by (used in) financing activities 1,076 5,210 (384 ) 62 162 6,126 Net increase (decrease) in cash and cash equivalents 1,168 — (100 ) (41 ) — 1,027 Cash and cash equivalents, beginning of period 474 — 154 215 — 843 Cash and cash equivalents, end of period $ 1,642 $ — $ 54 $ 174 $ — $ 1,870 Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (61 ) $ 254 $ (18 ) $ — $ 175 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (97 ) (1 ) — (98 ) Decrease in restricted cash 29 306 — — 335 Acquisitions — — 234 — 234 Net intercompany transfers (1,044 ) — — 1,044 — Other investing — 3 — — 3 Net cash provided by (used in) investing activities (1,015 ) 212 233 1,044 474 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of financing costs 1,753 15 — — 1,768 Repayments of borrowings, including debt extinguishment costs (504 ) (1,413 ) — — (1,917 ) Net intercompany transfers — 1,044 — (1,044 ) — Interest rate swap settlement payments (5 ) — — — (5 ) Net cash provided by (used in) financing activities 1,244 (354 ) — (1,044 ) (154 ) Net increase in cash and cash equivalents 168 112 215 — 495 Cash and cash equivalents, beginning of period 306 42 — — 348 Cash and cash equivalents, end of period $ 474 $ 154 $ 215 $ — $ 843

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	Note 21—Discontinued Operations On April 30, 2013, we completed the sale of Roseton. On November 1, 2013, the Danskammer assets were sold. Any activity related to our Roseton and Danskammer operations is included in Income from discontinued operations, net of tax in our consolidated statement of operations for the year ended December 31, 2013 . On November 4, 2013, the DNE Joint Plan of Liquidation became effective and Hudson Power, L.L.C., Danskammer and Roseton were deemed to have been merged into DNE or dissolved. On December 30, 2014, DNE was dissolved. The proceeds from the Facilities Sale Transactions of $1 million were distributed pursuant to the Joint Plan of Liquidation, including any modification thereto.

Restructuring Charges

Restructuring Charges	12 Months Ended
	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring Charges	Note 22—Restructuring Charges During the year ended December 31, 2013 , approximately 102 positions were eliminated, primarily related to the AER Acquisition. We paid approximately $3 million in severance benefits to affected employees during the year ended December 31, 2013 , which is included in Acquisition and integration costs on our consolidated statement of operations. During the year ended December 31, 2014 , approximately 106 positions were eliminated, primarily related to the AER Acquisition. We paid approximately $12 million in severance benefits to affected employees during the year ended December 31, 2014 , which is included in Acquisition and integration costs on our consolidated statement of operations. During the year ended December 31, 2015 , approximately 49 positions were eliminated, primarily related to the EquiPower Acquisition in April 2015. We paid approximately $14 million in severance benefits to affected employees during the year ended December 31, 2015 . We were reimbursed $3 million by ECP to cover a portion of these severance benefits during the year ended December 31, 2015 . These severance costs, net of the reimbursement, is included in Acquisition and integration costs on our consolidated statement of operations. The following table summarizes activity related to liabilities associated with costs related to severance and retention benefits: Year Ended December 31, (amounts in millions) 2015 2014 2013 Beginning of period $ — $ 12 $ 2 Expense (1) 16 3 14 Payments (15 ) (15 ) (4 ) End of period $ 1 $ — $ 12 __________________________________________ (1) Expense during the years ended December 31, 2015, 2014 and 2013 includes $1 million , $1 million and $3 million in retention benefits, respectively.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	Note 23—Segment Information We report the results of our operations in three segments: (i) Coal, (ii) IPH and (iii) Gas. The Coal segment includes certain of our coal-fired power generation facilities and our Dynegy Energy Services retail business. The IPH segment includes Genco, and Illinois Power Resources Generating, LLC (“IPRG”), which also own, directly and indirectly, certain of our coal-fired power generation facilities. IPH also includes our Homefield Energy retail business in Illinois. IPH and its direct and indirect subsidiaries and Genco and its direct and indirect subsidiaries are each organized into ring-fenced groups in order to maintain corporate separateness. The Gas segment includes substantially all of our natural gas-fired power generation facilities. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense). Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the years ended December 31, 2015, 2014 and 2013 is presented below: Segment Data as of and for the Year Ended December 31, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,298 $ 804 $ 1,768 $ — $ 3,870 Intercompany revenues (134 ) (5 ) 139 — — Total revenues $ 1,164 $ 799 $ 1,907 $ — $ 3,870 Depreciation expense $ (138 ) $ (29 ) $ (416 ) $ (4 ) $ (587 ) Impairments (99 ) — — — (99 ) Gain on sale of assets, net — — (1 ) — (1 ) General and administrative expense — — — (128 ) (128 ) Operating income (loss) $ (93 ) $ 49 $ 360 $ (252 ) $ 64 Earnings from unconsolidated investments — — 1 — 1 Interest expense — — — (546 ) (546 ) Other items, net (1 ) — — 55 54 Loss before income taxes (427 ) Income tax benefit — — — 474 474 Net loss 47 Less: Net income attributable to noncontrolling interest (3 ) Net loss attributable to Dynegy Inc. $ 50 Total assets—domestic $ 2,324 $ 897 $ 7,811 $ 507 $ 11,539 Investment in unconsolidated affiliate $ — $ — $ 190 $ — $ 190 Capital expenditures $ (87 ) $ (63 ) $ (112 ) $ (13 ) $ (275 ) Segment Data as of and for the Year Ended December 31, 2014 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 587 $ 850 $ 1,060 $ — $ 2,497 Intercompany revenues 6 (4 ) (2 ) — — Total revenues $ 593 $ 846 $ 1,058 $ — $ 2,497 Depreciation expense $ (51 ) $ (37 ) $ (155 ) $ (4 ) $ (247 ) Gain on sale of assets — — 18 — 18 General and administrative expense — — — (114 ) (114 ) Operating income (loss) $ 40 $ (2 ) $ 79 $ (136 ) $ (19 ) Bankruptcy reorganization items, net — — — 3 3 Earnings from unconsolidated investments — — 10 — 10 Interest expense — — — (223 ) (223 ) Other items, net — — — (39 ) (39 ) Loss from continuing operations before income taxes (268 ) Income tax benefit — — — 1 1 Loss from continuing operations (267 ) Net loss (267 ) Less: Net income (loss) attributable to noncontrolling interest 6 Net loss attributable to Dynegy Inc. $ (273 ) Total assets—domestic $ 1,168 $ 1,039 $ 2,027 $ 6,998 $ 11,232 Capital expenditures $ (39 ) $ (45 ) $ (44 ) $ (4 ) $ (132 ) Segment Data as of and for the Year Ended December 31, 2013 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 469 $ 67 $ 930 $ — $ 1,466 Intercompany revenues (2 ) — 2 — — Total revenues $ 467 $ 67 $ 932 $ — $ 1,466 Depreciation expense $ (50 ) $ (3 ) $ (160 ) $ (3 ) $ (216 ) Gain on sale of assets 2 — — — 2 General and administrative expense — — — (97 ) (97 ) Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 ) Bankruptcy reorganization items, net — — — (1 ) (1 ) Earnings from unconsolidated investments — — 2 — 2 Interest expense — — — (97 ) (97 ) Loss on extinguishment of debt (5 ) — 2 (8 ) (11 ) Other items, net — — 2 6 8 Loss from continuing operations before income taxes (417 ) Income tax benefit — — — 58 58 Loss from continuing operations (359 ) Income from discontinued operations, net of tax — — — 3 3 Net loss (356 ) Less: Net income (loss) attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (356 ) Total assets—domestic $ 1,153 $ 1,190 $ 2,303 $ 645 $ 5,291 Capital expenditures $ (42 ) $ (1 ) $ (53 ) $ (2 ) $ (98 ) Significant Customers Our total revenues for customers which individually accounted for more than 10% of our consolidated revenues, and the segments impacted, for the years ended December 31, 2015, 2014 and 2013 are presented below: Customers Revenues Segment(s) (amounts in millions) 2015 PJM $ 1,088 Coal, IPH, Gas MISO 842 Coal, IPH 2014 MISO $ 836 Coal, IPH NYISO 342 Gas 2013 MISO $ 526 Coal, IPH PJM 275 Gas NYISO 231 Gas CAISO 221 Gas

Subsequent Event Subsequent Eve

Subsequent Event Subsequent Event	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Event	Note 24—Subsequent Event On February 25, 2016, we announced the acquisition of certain power generation facilities from International Power, S.A., a wholly owned subsidiary of ENGIE, through a joint venture with ECP, for a purchase price of approximately $3.3 billion . The acquisition includes approximately 8,700 MW located in ERCOT, PJM and ISO-NE. Of the 8,700 MW, approximately 8,000 MW are modern, efficient natural gas facilities with the remaining 700 MW being environmentally compliant coal facilities. The joint venture will be approximately 65 percent owned by a subsidiary of Dynegy and approximately 35 percent by affiliates of ECP, and will be a non-recourse subsidiary of Dynegy. In addition to the joint venture, ECP will also purchase approximately $150 million of Dynegy common stock.

Summary of Significant Accoun33

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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. Intercompany accounts and transactions have been eliminated. Certain prior period amounts in our consolidated balance sheets 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, (ii) analyzing tangible and intangible assets for possible impairment, (iii) estimating the useful lives of our assets and Asset Retirement Obligations (“AROs”), (iv) assessing future tax exposure and the realization of deferred tax assets, (v) determining amounts to accrue for contingencies, guarantees and, indemnifications and (vi) 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, 2015, we had $39 million of restricted cash classified as current assets related to cash deposits associated with certain letters of credit. We included this change in restricted cash as an operating activity in our consolidated statements of cash flows. As of December 31, 2014, we had $5.1 billion of restricted cash classified as long-term assets and $113 million of prepaid interest classified as current assets related to the issuance of the Notes, as defined herein. Upon the close of the Acquisitions, as defined herein, the proceeds from the issuance of the Notes were released from escrow. Please read Note 13—Debt for further information. We included the changes in restricted cash related to the payment to the escrow agents for the Acquisitions and the prepayment of interest on the Notes as investing activities in our consolidated statements of cash flows. Payments to the escrow agents for interest accrued on the Notes are reflected as operating activities in our consolidated statements of cash flows.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts. We record accounts receivable at the 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 two to 40 years. The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 2 to 36 Buildings and improvements 2 to 40 Office and other equipment 3 to 20 Gains and losses on sales of individual assets or asset groups 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 such assets may not be recoverable. If an impairment is indicated, the carrying value is first compared to the undiscounted cash flows for the asset’s or asset group’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 or asset group’s fair value. As a result of our impairment analyses performed in 2015, we determined that our Brayton Point and Wood River facilities were impaired resulting in an aggregate impairment charge of $99 million for the year ended December 31, 2015.
Undivided Interest Accounting
Goodwill, Intangible Assets and Liabilities	Goodwill. Goodwill represents, at the time of an acquisition, the excess of purchase price over fair value of net assets acquired. The carrying amount of our goodwill will be periodically reviewed, at least annually, for impairment and whenever events or changes in circumstances indicate that the carrying value may not be recoverable. In accordance with Accounting Standards Codification (“ASC”) 350, Intangibles-Goodwill and Other, we can opt to perform a qualitative assessment to test goodwill for impairment or we can directly perform a two-step impairment test. Based on our qualitative assessment, if we determine that the fair value of a reporting unit is more likely than not (i.e., a likelihood of more than 50 percent) to be less than its carrying amount, the two-step impairment test will be performed. In the absence of sufficient qualitative factors, goodwill impairment is determined using a two-step process: • Step one—Identify potential impairment by comparing the fair value of a reporting unit to the book value, including goodwill. If the fair value exceeds book value, the goodwill of the reporting unit is not considered impaired. If the book value exceeds fair value, proceed to step two. • Step two—Compare the implied fair value of the reporting unit’s goodwill to the book value of the reporting unit’s goodwill. If the book value of goodwill exceeds the implied fair value, an impairment charge is recognized for the excess. As of December 31, 2015, we concluded that, due to the decrease in our stock price, it was more likely than not that the fair value of goodwill attributed to the reporting units in the Gas segment was less than its carrying amount. As a result, we performed a quantitative impairment analysis using a Discounted Cash Flow (“DCF”) model for each of the reporting units to which we assigned goodwill and determined that the fair value of the reporting units exceeded their respective carrying amounts, inclusive of goodwill. Therefore, as of December 31, 2015 , no impairment loss related to goodwill was required. Intangible Assets and Liabilities. We initially record and measure intangible assets and liabilities (“Intangibles”) based on the fair value of those rights transferred in the transaction in which the asset was acquired. All recognized Intangibles consist of contractual rights and obligations with finite lives. The Intangibles 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 based on the useful life of the respective contract or contracts.
Asset Retirement Obligations	Asset Retirement Obligations. We record the present value of our legal obligations to retire tangible, long-lived assets on our consolidated balance sheets as liabilities when the liability is incurred. Our AROs relate to activities such as Coal Combustion Residuals (“CCR”) surface impoundments and landfill closure, dismantlement of power generation facilities, future removal of asbestos-containing material from certain power generation facilities, closure and post-closure costs, environmental testing, remediation, monitoring and land obligations. Accretion expense is included in Operating and maintenance expense on our consolidated statements of operations. A summary of changes in our AROs is as follows: Year Ended December 31, (amounts in millions) 2015 2014 Balance at beginning of year $ 224 $ 181 Accretion expense 21 12 Liabilities incurred 4 — Liabilities settled (4 ) (2 ) Revision of previous estimate (1) (57 ) 33 Acquisitions (2) 92 — Balance at end of year $ 280 $ 224 __________________________________________ (1) During 2015, we revised our ARO downward by $57 million based on management’s review and assessment of CCR compliance timing and site-specific analysis. During 2014, we revised our ARO upward by $33 million based on observed trends in Illinois, primarily related to CCR surface impoundment closures and landfills in accordance with the standards used in the industry. (2) As a result of the Acquisitions in April 2015, the associated AROs were assumed.
Contingencies, Commitments, Guarantees and Indemnifications	Contingencies, Commitments, Guarantees and Indemnifications. We are involved in numerous lawsuits, claims, proceedings and tax-related audits 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 on 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 for litigation matters, 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 disclose and account for various guarantees and indemnifications entered into during the 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. Our preferred shares are mandatorily convertible, are not redeemable and are classified as stockholders’ equity. We present the gross proceeds from their issuance as a single line item within stockholders’ equity on the consolidated balance sheets. Dividends on the preferred shares are cumulative and are presented as a reduction of net income (or increase of net loss) to derive net income (loss) attributable to common shareholders on the consolidated statements of operations. Dividends are recognized in stockholders’ equity in the period in which they are declared, and are presented as a financing activity on the consolidated statements of cash flows when paid.
Treasury Stock	Treasury Stock. Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock, which is presented on our 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 on 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 earnings. 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 and cap agreements. We elect not to apply hedge accounting to our interest rate derivative contracts; therefore, changes in fair value are recorded currently in earnings through interest expense. Cash settlements related to our current interest rate contracts are classified as either inflows or outflows from financing activities on the consolidated cash flow statements due to an other-than-insignificant financing element at inception of these contracts. 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. IPH and its subsidiaries (ring-fenced entities) operate under a tax sharing agreement with Dynegy. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences as of each reporting date. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation for tax and accounting purposes. These differences can result in deferred tax assets and liabilities which are included within our consolidated balance sheets. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business. The Company routinely assesses the realizability of its deferred tax assets. If the Company concludes that it is more likely than not that some or all of the deferred tax assets will not be realized, the tax asset is reduced by a valuation allowance. In making this determination, we consider all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies. Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. Please read Note 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 stock options and warrants are exercised and restricted stock units and performance stock units are fully vested under the treasury stock method. Diluted earnings (loss) per share also includes the effect of the assumed conversion of our convertible preferred stock 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.
Accounting Principles Adobted	Accounting Standards Adopted Income Taxes. In November 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2015-17-Income Taxes (Topic 740). The amendment in this ASU eliminates the current requirement for organizations to present deferred tax liabilities and assets as current and noncurrent in a classified balance sheet. Instead, organizations will be required to classify all deferred tax assets and liabilities as noncurrent. The guidance in this ASU is effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. Earlier application is permitted for all entities as of the beginning of an interim or annual reporting period. The ASU may be applied prospectively to all deferred tax assets and liabilities or retrospectively to all periods presented. We adopted ASU 2015-17 as of December 31, 2015 and applied the guidance prospectively with no change to prior period amounts disclosed in our consolidated balance sheets and related notes to the consolidated financial statements. Please read Note 14—Income Taxes for further discussion. Business Combinations. In September 2015, the FASB issued ASU 2015-16-Business Combinations (Topic 805). The amendments in this ASU require that an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. The amendments in this ASU require that the acquirer record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The amendments in this ASU require an entity to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted for financial statements that have not been issued. We adopted ASU 2015-16 as of September 30, 2015. Please read Note 3—Acquisitions for a summary of the impact on our consolidated financial statements. Derivatives. In August 2015, the FASB issued ASU 2015-13-Derivatives and Hedging (Topic 815). The amendments in this ASU specify that the use of LMP by an ISO does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis and, therefore, does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales scope exception. If the physical delivery criterion is met, along with all of the other criteria of the normal purchases and normal sales scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments in this ASU are effective upon issuance and should be applied prospectively. The adoption of this ASU did not have a material impact on our consolidated financial statements. Inventory. In July 2015, the FASB issued ASU 2015-11-Inventory (Topic 330). The amendments in this ASU require that inventory is measured at the lower of cost or NRV, with the latter defined as the estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation. This ASU eliminates the need to determine market or replacement cost and evaluate whether it is above the ceiling at NRV or below the floor (NRV less a normal profit margin). The guidance in this ASU is effective prospectively for interim and annual periods beginning after December 15, 2016, with early adoption permitted. We adopted ASU 2015-11 as of July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Retirement Benefits. In April 2015, the FASB issued ASU 2015-04-Compensation-Retirement Benefits (Topic 715). For an entity that has a significant event in an interim period that calls for a remeasurement of defined benefit plan or post retirement plan assets and obligations, the amendments in this ASU provide a practical expedient that permits the entity to remeasure the plan assets and obligations using the month-end that is closest to the date of the significant event. The month-end remeasurement of defined benefit plan assets and obligations that is closest to the date of the significant event should be adjusted for any effects of the significant event that may or may not be captured in the month-end measurement. An entity is required to disclose the accounting policy election and the date used to measure defined benefit plan assets and obligations in accordance with the amendments in this ASU. The amendments in this ASU are effective for public business entities for financial statements issued for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years, with early adoption allowed. The amendments in this ASU should be applied prospectively. We adopted the guidance in this ASU on July 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements. Reporting Discontinued Operations and Asset Disposals. In April 2014, the FASB issued ASU 2014-08-Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosure of Disposals of Components of an Entity. The amendments in this ASU change the requirements for reporting discontinued operations in Subtopic 205-20. An entity is required to report within discontinued operations on the statement of operations the results of a component or group of components of an entity if the disposal represents a strategic shift that has, or will have, a major effect on an entity’s operations and financial results. Additionally, the associated assets and liabilities are required to be presented separately from other assets and liabilities on the balance sheet for all comparative periods. The ASU includes updated guidance regarding what meets the definition of a component of an entity. The new financial statement presentation provisions relating to this ASU are prospective and effective for interim and annual periods beginning after December 15, 2014, with early adoption permitted. We adopted the guidance in this ASU on January 1, 2015. The adoption of this ASU did not have a material impact on our consolidated financial statements or disclosures.
Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. The guidance in these ASUs is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted. The adoption of these ASUs should be applied on a retrospective basis, affecting all balance sheet periods presented. We do not anticipate the adoption of these ASUs will have a material impact on our consolidated balance sheets. Consolidation. In February 2015, the FASB issued ASU 2015-02-Consolidation (Topic 810). The amendments in this ASU respond to concerns about the current accounting for consolidation of certain legal entities, in particular: (i) consolidation of limited partnerships and similar legal entities, (ii) evaluating fees paid to a decision maker or a service provider as a variable interest, (iii) the effect of fee arrangements on the primary beneficiary determination, (iv) the effect of related parties on the primary beneficiary determination and (v) consolidation of certain investment funds. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2015, with early adoption permitted in an interim period. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. Reporting entities may elect to apply the amendments prospectively only, or retrospectively for all prior periods presented in the financial statements. Early adoption is permitted provided that the guidance is applied from the beginning of the fiscal year of adoption. We do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board (“IASB”) jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU was further updated through the issuance of ASU 2015-14 in August 2015. The amendments in this ASU develop a common revenue standard for GAAP and International Financial Reporting Standards (“IFRS”) by removing inconsistencies and weaknesses in revenue requirements, providing a more robust framework for addressing revenue issues, improving comparability of revenue recognition practices, providing more useful information to users of financial statements and simplifying the preparation of financial statements. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our consolidated financial statements.

Summary of Significant Accoun34

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Property, Plant and Equipment	The estimated economic service lives of our asset groups are as follows: Asset Group Range of Years Power generation 2 to 36 Buildings and improvements 2 to 40 Office and other equipment 3 to 20 A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Power generation $ 8,178 $ 3,174 Buildings and improvements 956 457 Office and other equipment 101 54 Property, plant and equipment 9,235 3,685 Accumulated depreciation (888 ) (430 ) Property, plant and equipment, net $ 8,347 $ 3,255
Schedule of Change in Asset Retirement Obligation	A summary of changes in our AROs is as follows: Year Ended December 31, (amounts in millions) 2015 2014 Balance at beginning of year $ 224 $ 181 Accretion expense 21 12 Liabilities incurred 4 — Liabilities settled (4 ) (2 ) Revision of previous estimate (1) (57 ) 33 Acquisitions (2) 92 — Balance at end of year $ 280 $ 224 __________________________________________ (1) During 2015, we revised our ARO downward by $57 million based on management’s review and assessment of CCR compliance timing and site-specific analysis. During 2014, we revised our ARO upward by $33 million based on observed trends in Illinois, primarily related to CCR surface impoundment closures and landfills in accordance with the standards used in the industry. (2) As a result of the Acquisitions in April 2015, the associated AROs were assumed.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2015
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 EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 127 176 Inventory 167 105 272 Assets from risk management activities (including current portion of $4 million and $30 million, respectively) 4 33 37 Prepayments and other current assets 32 69 101 Property, plant and equipment 2,773 2,734 5,507 Investment in unconsolidated affiliate 200 — 200 Intangible assets (including current portion of $67 million and $36 million, respectively) 111 84 195 Other long-term assets 28 35 63 Total assets acquired 3,631 3,187 6,818 Accounts payable 27 97 124 Accrued liabilities and other current liabilities 22 10 32 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 506 — 506 Other long-term liabilities — 40 40 Total liabilities assumed 767 396 1,163 Identifiable net assets acquired 2,864 2,791 5,655 Goodwill 797 — 797 Net assets acquired $ 3,661 $ 2,791 $ 6,452
Pro Forma Financial Results Related to Acquisition	The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisitions been completed on January 1, 2014, nor are they indicative of future results of operations. Year Ended December 31, (amounts in millions) 2015 2014 Revenues $ 4,860 $ 5,574 Net income (loss) $ 308 $ (613 ) Net income (loss) attributable to noncontrolling interest $ (3 ) $ 6 Net income (loss) attributable to Dynegy Inc. $ 311 $ (619 )

Risk Management Activities, D36

Risk Management Activities, Derivatives and Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts and Interest Rate Swaps	The following table summarizes our cash collateral posted as of December 31, 2015 and 2014 , within Prepayments and other current assets on our consolidated balance sheets, and the amount applied against short-term risk management activities: Location on balance sheet December 31, 2015 December 31, 2014 (amounts in millions) Gross collateral posted with counterparties $ 162 $ 49 Less: Collateral netted against risk management liabilities 106 9 Net collateral within Prepayments and other current assets $ 56 $ 40 As of December 31, 2015 , 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) (45 ) MWh $ (1 ) Electricity basis derivatives (3) (29 ) MWh $ 24 Natural gas derivatives (2) 305 MMBtu $ (143 ) Natural gas basis derivatives 69 MMBtu $ (7 ) Diesel fuel 3 Gallon $ (4 ) Coal derivatives (4) — Metric Ton $ (23 ) Interest rate swaps 777 U.S. Dollar $ (42 ) Common stock warrants (5) 16 Warrant $ (7 ) _________________________________________ (1) Includes both asset and liability risk management positions, but excludes margin and collateral netting of $106 million . (2) Mainly comprised of swaps, options and physical forwards. (3) Comprised of FTRs and swaps. (4) Our net position rounds to less than 1 million tons. (5) Each warrant is convertible into one share of Dynegy common stock.
Schedule of Derivative Instruments in the Balance Sheet, Fair Value	The following table presents the fair value and balance sheet classification of derivatives in our consolidated balance sheets as of December 31, 2015 and 2014 . As of December 31, 2015 and 2014 , there were no gross amounts available to be offset that were not offset in our consolidated balance sheets. December 31, 2015 Gross amounts offset in the balance sheet Contract Type Balance Sheet Location Gross Fair Value Contract Netting Collateral or Margin Received or Paid Net Fair Value (amounts in millions) Derivative assets: Commodity contracts Assets from risk management activities $ 403 $ (285 ) $ $ 118 Total derivative assets $ 403 $ (285 ) $ — $ 118 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (557 ) $ 285 $ 106 $ (166 ) Interest rate contracts Liabilities from risk management activities (42 ) — — (42 ) Common stock warrants Other long-term liabilities (7 ) — — (7 ) Total derivative liabilities $ (606 ) $ 285 $ 106 $ (215 ) Total derivatives $ (203 ) $ $ 106 $ (97 ) December 31, 2014 Gross amounts offset in the balance sheet Contract Type Balance Sheet Location Gross Fair Value Contract Netting Collateral or Margin Received or Paid Net Fair Value (amounts in millions) Derivative assets: Commodity contracts Assets from risk management activities $ 115 $ (35 ) $ $ 80 Total derivative assets $ 115 $ (35 ) $ — $ 80 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (163 ) $ 35 $ 9 $ (119 ) Interest rate contracts Liabilities from risk management activities (44 ) — — (44 ) Common stock warrants Other long-term liabilities (61 ) — — (61 ) Total derivative liabilities $ (268 ) $ 35 $ 9 $ (224 ) Total derivatives $ (153 ) $ $ 9 $ (144 )
Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations	Our consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 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, 2015 2014 2013 (amounts in millions) Commodity contracts Revenues $ 194 $ (183 ) $ (101 ) Interest rate contracts Interest expense $ (15 ) $ (15 ) $ (7 ) Common stock warrants Other income (expense), net $ 54 $ (40 ) $ (1 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 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, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 308 $ 40 $ 348 Natural gas derivatives — 40 2 42 Coal derivatives — 10 3 13 Total assets from commodity risk management activities $ — $ 358 $ 45 $ 403 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (267 ) $ (58 ) $ (325 ) Natural gas derivatives — (158 ) (34 ) (192 ) Diesel fuel derivatives — (4 ) — (4 ) Coal derivatives — (35 ) (1 ) (36 ) Total liabilities from commodity risk management activities — (464 ) (93 ) (557 ) Liabilities from interest rate contracts — (42 ) — (42 ) Liabilities from outstanding common stock warrants (7 ) — — (7 ) Total liabilities $ (7 ) $ (506 ) $ (93 ) $ (606 ) Fair Value as of December 31, 2014 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 88 $ 22 $ 110 Natural gas derivatives — 3 — 3 Emissions derivatives — 2 — 2 Total assets from commodity risk management activities $ — $ 93 $ 22 $ 115 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (27 ) $ (26 ) $ (53 ) Natural gas derivatives — (100 ) — (100 ) Diesel fuel derivatives — (6 ) — (6 ) Crude oil derivatives — (3 ) — (3 ) Coal derivatives — (1 ) — (1 ) Total liabilities from commodity risk management activities — (137 ) (26 ) (163 ) Liabilities from interest rate contracts — (44 ) — (44 ) Liabilities from outstanding common stock warrants (61 ) — — (61 ) Total liabilities $ (61 ) $ (181 ) $ (26 ) $ (268 )
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, 2015 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Inputs Significant Unobservable Inputs Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (4 ) Million MWh $ (11 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs 24 Million MWh $ (7 ) Historical congestion Forward price $0 - $1.00 Natural gas derivatives (1) 96 Million MMBtu $ (32 ) Illiquid location fixed price Forward price $1.40 - $1.70 Coal derivatives (1) — Thousand Tons $ 2 Illiquid location fixed price Forward price $4.35 - $5.35 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations.
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, 2015 (amounts in millions) Electricity Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Total gains included in earnings 39 3 — — 42 Settlements (1) 1 28 9 (2 ) 36 Acquisitions (54 ) (63 ) (9 ) 4 (122 ) Balance at December 31, 2015 $ (18 ) $ (32 ) $ — $ 2 $ (48 ) Unrealized gains relating to instruments held as of December 31, 2015 $ 39 $ 3 $ — $ — $ 42 Year Ended December 31, 2014 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2013 $ 11 $ — $ (1 ) $ — $ 10 Total gains (losses) included in earnings (9 ) — 1 — (8 ) Settlements (1) (6 ) — — — (6 ) Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Unrealized gains (losses) relating to instruments held as of December 31, 2014 $ (9 ) $ — $ 1 $ — $ (8 ) Year Ended December 31, 2013 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2012 $ 5 $ — $ 2 $ — $ 7 Total gains (losses) included in earnings (4 ) — 1 — (3 ) Settlements (1) (6 ) — (3 ) — (9 ) AER Acquisition 16 — (1 ) — 15 Balance at December 31, 2013 $ 11 $ — $ (1 ) $ — $ 10 Unrealized gains (losses) relating to instruments held as of December 31, 2013 $ (4 ) $ — $ 1 $ — $ (3 ) __________________________________________ (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, 2015 and 2014 . December 31, 2015 December 31, 2014 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (2)(6) $ (2,100 ) $ (1,985 ) $ (2,100 ) $ (2,132 ) Tranche B-2 Term Loan, due 2020 (1)(2) $ (778 ) $ (754 ) $ (785 ) $ (775 ) 7.375% Senior Notes, due 2022 (2)(6) $ (1,750 ) $ (1,531 ) $ (1,750 ) $ (1,777 ) 5.875% Senior Notes, due 2023 (2) $ (500 ) $ (404 ) $ (500 ) $ (475 ) 7.625% Senior Notes, due 2024 (2)(6) $ (1,250 ) $ (1,078 ) $ (1,250 ) $ (1,272 ) Inventory financing agreements (2) $ (136 ) $ (136 ) $ (23 ) $ (23 ) Equipment financing agreements (7) $ (61 ) $ (61 ) $ — $ — Interest rate derivatives (2) $ (42 ) $ (42 ) $ (44 ) $ (44 ) Commodity-based derivative contracts (3) $ (154 ) $ (154 ) $ (48 ) $ (48 ) Common stock warrants (4) $ (7 ) $ (7 ) $ (61 ) $ (61 ) Genco: 7.00% Senior Notes Series H, due 2018 (2)(5) $ (276 ) $ (204 ) $ (268 ) $ (264 ) 6.30% Senior Notes Series I, due 2020 (2)(5) $ (213 ) $ (148 ) $ (206 ) $ (208 ) 7.95% Senior Notes Series F, due 2032 (2)(5) $ (225 ) $ (162 ) $ (224 ) $ (241 ) __________________________________________ (1) Carrying amount includes an unamortized discount of $2 million and $3 million as of December 31, 2015 and 2014 , respectively. Please read Note 13—Debt for further discussion. (2) The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels. (3) Carrying amount of commodity-based derivative contracts excludes $106 million and $9 million of cash posted as collateral, as of December 31, 2015 and 2014 , respectively. (4) The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels. (5) Combined carrying amounts as of December 31, 2015 and 2014 include unamortized discounts of $111 million and $127 million , respectively. Please read Note 13—Debt for further discussion. (6) At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”). (7) Carrying amounts for the equipment financing agreements include unamortized discounts of $14 million as of December 31, 2015 . In addition, the fair value is classified as Level 3 within the fair value hierarchy levels.

Accumulated Other Comprehensi38

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
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) 2015 2014 2013 Beginning of period $ 20 $ 58 $ 11 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments (net of tax of zero, zero and $31, respectively) 3 (33 ) 56 Amounts reclassified from accumulated other comprehensive income: Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively) (1) — — (7 ) Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero and zero, respectively) (2) (4 ) (5 ) (2 ) Net current period other comprehensive income (loss), net of tax (1 ) (38 ) 47 End of period (3) $ 19 $ 20 $ 58 __________________________________________ (1) Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion. (3) Includes a tax impact of $31 million due to remeasurements of certain of our pension and other post-employment benefit plans in 2013 that will only reverse if and when the Dynegy plans terminate.

Cash Flow Information (Tables)

Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
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) 2015 2014 2013 Interest paid (net of amount capitalized) $ 491 $ 120 $ 92 Taxes paid (net of refunds) $ 2 $ — $ (1 ) Other non-cash investing and financing activity: Non-cash capital expenditures (1) $ 10 $ 23 $ (3 ) Non-cash capital expenditures pursuant to an equipment financing agreement $ 61 $ — $ — Acquisition consideration (2) $ 105 $ — $ 7 __________________________________________ (1) These expenditures are primarily for changes in our accruals of capital expenditures for all years presented. (2) Represents the consideration given by us for acquisitions. Please read Note 3—Acquisitions for further discussion.

Inventory (Tables)

Inventory (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Summary of inventories	A summary of our inventories is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Materials and supplies $ 175 $ 83 Coal (1) 350 119 Fuel oil (1) 17 3 Emissions allowances (2) 51 2 Other 4 1 Total $ 597 $ 208 __________________________________________ (1) At December 31, 2015 , approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt —Brayton Point Inventory Financing for further discussion. (2) At December 31, 2015 , a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt —Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
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 2 to 36 Buildings and improvements 2 to 40 Office and other equipment 3 to 20 A summary of our property, plant and equipment is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Power generation $ 8,178 $ 3,174 Buildings and improvements 956 457 Office and other equipment 101 54 Property, plant and equipment 9,235 3,685 Accumulated depreciation (888 ) (430 ) Property, plant and equipment, net $ 8,347 $ 3,255
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) 2015 2014 2013 Total interest costs incurred $ 487 $ 187 $ 86 Capitalized interest $ 12 $ 9 $ 2

Joint Ownership of Generating42

Joint Ownership of Generating Facilities (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following table presents the ownership interests of the jointly owned facilities included in our consolidated balance sheets. Each facility is co-owned with one or more other generation companies. December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy.

Intangible Assets and Liabili43

Intangible Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014: December 31, 2015 December 31, 2014 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (126 ) $ 134 $ 111 $ (46 ) $ 65 Gas transport contracts 46 (16 ) 30 — — — Total intangible assets $ 306 $ (142 ) $ 164 $ 111 $ (46 ) $ 65 Intangible Liabilities: Electricity contracts $ (30 ) $ 19 $ (11 ) $ (20 ) $ 14 $ (6 ) Coal contracts (134 ) 82 (52 ) (41 ) 22 (19 ) Coal transport contracts (104 ) 64 (40 ) (81 ) 32 (49 ) Gas transport contracts (64 ) 27 (37 ) (24 ) 17 (7 ) Total intangible liabilities $ (332 ) $ 192 $ (140 ) $ (166 ) $ 85 $ (81 ) Intangible assets and liabilities, net $ (26 ) $ 50 $ 24 $ (55 ) $ 39 $ (16 ) The following table presents our amortization expense (revenue) of intangible assets and liabilities for the past three years during the years ended December 31, 2015, 2014 and 2013 : Year Ended December 31, (amounts in millions) 2015 2014 2013 Electricity contracts, net (1) $ 75 $ 96 $ 136 Coal contracts, net (2) (60 ) (14 ) 129 Coal transport contracts (2) (32 ) (29 ) (7 ) Gas transport contracts (2) 6 (8 ) (7 ) Total $ (11 ) $ 45 $ 251 __________________________________________ (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.
Schedule of Acquired Finite-Lived Intangible Assets and Liabilities by Major Class	The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the Acquisitions in April 2015: EquiPower Acquisition Duke Midwest Acquisition (amounts in millions/months) Gross Carrying Amount Weighted-Average Amortization Period Gross Carrying Amount Weighted-Average Amortization Period Intangible Assets: Electricity contracts $ 68 31 $ 80 38 Coal contracts — — — 9 Gas transport contracts 43 28 4 19 Total intangible assets $ 111 30 $ 84 37 Intangible Liabilities: Electricity contracts $ — — $ (10 ) 23 Coal contracts (10 ) 21 (83 ) 27 Coal transport contracts (23 ) 22 — — Gas contracts — 1 — — Gas transport contracts (40 ) 128 — — Total intangible liabilities $ (73 ) 81 $ (93 ) 27 Total intangible assets and liabilities, net $ 38 $ (9 )

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	A summary of our long-term debt is as follows: (amounts in millions) December 31, 2015 December 31, 2014 Dynegy Inc.: 6.75% Senior Notes, due 2019 (1) $ 2,100 $ 2,100 Tranche B-2 Term Loan, due 2020 780 788 7.375% Senior Notes, due 2022 (1) 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 (1) 1,250 1,250 Revolving Facility — — Inventory Financing Agreements 136 23 Equipment Financing Agreements 75 — Genco: 7.00% Senior Notes Series H, due 2018 300 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 7,416 7,236 Unamortized discounts on debt, net (127 ) (130 ) 7,289 7,106 Less: Current maturities, including unamortized discounts, net 83 31 Total Long-term debt $ 7,206 $ 7,075 __________________________________________ (1) At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”).
Genco Compliance Ratios	The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% __________________________________________ (1) As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. (2) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from third-party external sources are included in the definition of indebtedness and are subject to these incurrence tests.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	Our components of income tax (expense) benefit related to income (loss) from continuing operations were as follows: Year Ended December 31, (amounts in millions) 2015 2014 2013 Current tax expense $ (3 ) $ — $ (9 ) Deferred tax benefit 477 1 67 Income tax benefit $ 474 $ 1 $ 58
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) 2015 2014 2013 Expected tax benefit at U.S. statutory rate (35%) $ 149 $ 94 $ 146 State taxes 68 — 3 Permanent differences (1) 16 (15 ) 2 Valuation allowance (2)(3)(4) 271 (331 ) (22 ) Uncertain tax position — 244 (67 ) Unconsolidated subsidiary adjustment — 5 — Adjustment to AMT credits (26 ) — — Other (4 ) 4 (4 ) Income tax benefit $ 474 $ 1 $ 58 __________________________________________ (1) Permanent items for 2015 and 2014 included an $18 million benefit and $14 million expense, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes. (2) The AER Acquisition in 2013 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $36 million reduction to our valuation allowance in connection with the AER Acquisition. In addition, 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. (3) Pre-tax income from components other than continuing operations provided a source of income that allowed for the reduction of the valuation allowance from continuing operations the year ended December 31, 2013. (4) On April 14, 2014, we received final notice from the Internal Revenue Service (“IRS”) that their audit of our 2012 tax year has been completed. In accordance with accounting guidance in ASC 740, Income Taxes (“ASC 740”), we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in the second quarter of 2014 as a discrete item with a corresponding adjustment to the valuation allowance.
Schedule of Deferred Tax Assets and Liabilities	Deferred Tax Liabilities and Assets. Our significant components of deferred tax assets and liabilities were as follows: Year Ended December 31, (amounts in millions) 2015 2014 Current: Deferred tax assets: Reserves (legal, environmental and other) $ — $ 5 Intangible contracts and other — 44 Derivative contracts — 28 Other — 9 Subtotal — 86 Less: valuation allowance — (72 ) Total current deferred tax assets — 14 Deferred tax liabilities: Derivative contracts — (23 ) Other — (11 ) Total current deferred tax liabilities — (34 ) Net current deferred tax liabilities — (20 ) Non-current: Deferred tax assets: NOL carryforwards 1,533 1,305 AMT and state tax credit carryforwards 275 280 Reserves (legal, environmental and other) 17 6 Pension and other post-employment benefits 16 20 Asset retirement obligations 89 81 Deferred financing costs and intangible/other contracts 64 40 Derivative contracts 69 14 Other 27 14 Subtotal 2,090 1,760 Less: valuation allowance (1,276 ) (1,463 ) Total non-current deferred tax assets 814 297 Deferred tax liabilities: Depreciation and other property differences (738 ) (209 ) Deferred financing costs and power contracts — — Investment in unconsolidated partnership (27 ) — Derivative contracts (4 ) (14 ) Other (74 ) (54 ) Total non-current deferred tax liabilities (843 ) (277 ) Net non-current deferred tax assets (liabilities) (29 ) 20 Net deferred tax liability $ (29 ) $ —
Summary of Valuation Allowance	The changes in the valuation allowance were as follows: (amounts in millions) Balance at Beginning of Period Charged to Costs and Expenses Charged to Other Accounts Additions/ (Deductions) Balance at End of Period Year Ended December 31, 2015 Changes in valuation allowance—continuing operations $ 1,535 (259 ) — — $ 1,276 Year Ended December 31, 2014 Changes in valuation allowance—continuing operations $ 1,149 370 16 — $ 1,535 Year Ended December 31, 2013 Changes in valuation allowance—continuing operations $ 1,121 28 — — $ 1,149
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of our beginning and ending amounts of unrecognized tax benefits follows: Year Ended December 31, amounts in millions 2015 2014 2013 Unrecognized tax benefits, beginning of period $ 4 $ 274 $ 1 Increase based on tax positions related to the prior period — — 273 Decrease due to settlements and payments (1 ) (270 ) — Unrecognized tax benefits, end of period $ 3 $ 4 $ 274

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The reconciliation of basic earnings (loss) per share to diluted earnings (loss) per share from continuing operations attributable to our common stockholders during the years ended December 31, 2015, 2014 and 2013 is shown in the following table. Year Ended December 31, (in millions, except per share amounts) 2015 2014 2013 Income (loss) from continuing operations $ 47 $ (267 ) $ (359 ) Less: Net income (loss) attributable to noncontrolling interest (3 ) 6 — Income (loss) from continuing operations attributable to Dynegy Inc. 50 (273 ) (359 ) Less: Dividends on preferred stock 22 5 — Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted earnings (loss) per share $ 28 $ (278 ) $ (359 ) Basic weighted-average shares 125 105 100 Effect of dilutive securities (1) 1 — — Diluted weighted-average shares 126 105 100 Basic and diluted earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders (1) $ 0.22 $ (2.65 ) $ (3.59 ) __________________________________________ (1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2014 and 2013 .
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	For the years ended December 31, 2015, 2014 and 2013 , the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive: Year Ended December 31, (in millions of shares) 2015 2014 2013 Stock options 0.5 1.4 1.0 Restricted stock units — 1.0 0.7 Performance stock units — 0.3 0.1 Warrants 15.6 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 4.0 — Total 29.0 22.3 17.4

Capital Stock (Tables)

Capital Stock (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Share-based Compensation, Stock Options, Activity	The following summarizes our stock option activity: Year Ended December 31, 2015 Options (in thousands) Weighted Average Exercise Price Weighted Average Remaining Contractual Life (in years) Aggregate Intrinsic Value Outstanding at beginning of period 1,372 $ 21.15 Granted 485 $ 27.43 Exercised (25 ) $ 20.93 Outstanding at end of period 1,832 $ 22.81 8.54 $ — Vested and unvested expected to vest 1,832 $ 22.81 8.54 $ — Exercisable at end of period 945 $ 20.38 7.27 $ —
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, 2015 2014 2013 Dividend Yield $ — $ — $ — Expected volatility (1) 27.70 % 23.96 % 32.79 % Risk-free interest rate (2) 1.64 % 1.61 % 1.05 % Expected option life (3) 5.5 years 5.5 years 5.5 years __________________________________________ (1) For the years ended December 31, 2015 and 2014 , the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012. For the year ended December 31, 2013, the expected volatility was calculated based on five -year historical volatilities of the stock of comparable companies whose shares are traded using daily stock price returns equivalent to the expected term of the options. (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: Year Ended December 31, 2015 RSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 1,046 $ 22.94 Granted 878 $ 28.93 Vested and released (468 ) $ 22.53 Forfeited (43 ) $ 25.83 Outstanding at end of period 1,413 $ 26.71 The following summarizes our PSU activity: Year Ended December 31, 2015 PSUs (in thousands) Weighted Average Grant Date Fair Value Outstanding at beginning of period 304 $ 23.13 Granted 278 $ 27.54 Vested and released — $ — Forfeited (6 ) $ 27.07 Outstanding at end of period 576 $ 25.22

Employee Compensation, Saving48

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures	These amounts include the obligations, plan assets and funded status of EEI’s pension and post-employment plans. Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Benefit obligation, beginning of the year $ 408 $ 390 $ 95 $ 81 Service cost 14 12 1 1 Interest cost 18 17 4 4 Actuarial (gain) loss (20 ) 40 (12 ) 15 Benefits paid (26 ) (37 ) (5 ) (6 ) Plan change — — (10 ) — Settlements — (14 ) (1 ) — Duke Midwest Acquisition 89 — 2 — Benefit obligation, end of the year $ 483 $ 408 $ 74 $ 95 Fair value of plan assets, beginning of the year $ 364 $ 373 $ 68 $ 67 Actual return on plan assets (13 ) 39 2 5 Employer contributions 4 3 — — Benefits paid (26 ) (37 ) (3 ) (4 ) Settlements — (14 ) — — Duke Midwest Acquisition 81 — — — Fair value of plan assets, end of the year $ 410 $ 364 $ 67 $ 68 Funded status $ (73 ) $ (44 ) $ (7 ) $ (27 )
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) 2015 2014 2015 2014 Non-current assets $ 5 $ 1 $ 23 $ 15 Current liabilities — — (2 ) (2 ) Non-current liabilities (78 ) (45 ) (28 ) (40 ) Net amount recognized $ (73 ) $ (44 ) $ (7 ) $ (27 )
Schedule of Amounts Recognized in Other Comprehensive Income (Loss)	Pre-tax amounts recognized in AOCI consist of: Pension Benefits Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2015 2014 Prior service credit $ (11 ) $ (12 ) $ (34 ) $ (27 ) Actuarial loss (gain) (6 ) (21 ) 2 12 Net gain recognized $ (17 ) $ (33 ) $ (32 ) $ (15 ) The expected amounts that will be amortized from AOCI and recognized as components of net periodic benefit cost (gain) in 2016 are as follows: (amounts in millions) Pension Benefits Other Benefits Prior service credit $ (1 ) $ (4 ) Actuarial (gain) loss — — Net gain recognized $ (1 ) $ (4 )
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) 2015 2014 2013 Service cost benefits earned during period $ 14 $ 12 $ 9 Interest cost on projected benefit obligation 18 17 14 Expected return on plan assets (23 ) (21 ) (19 ) Amortization of: Prior service credit (1 ) (1 ) (1 ) Actuarial gain — (1 ) — Net periodic benefit cost 8 6 3 Curtailment gain (1) — — (7 ) Total benefit cost (gain) $ 8 $ 6 $ (4 ) __________________________________________ (1) The curtailment gain was related to the DNE pension plan and resulted from the Roseton sale and the termination of a majority of the Danskammer employees. Other Benefits Year Ended December 31, (amounts in millions) 2015 2014 2013 Service cost benefits earned during period $ 1 $ 1 $ 1 Interest cost on projected benefit obligation 4 4 2 Expected return on plan assets (4 ) (4 ) — Amortization of: Prior service credit (3 ) (3 ) (1 ) Net periodic benefit cost (gain) (2 ) (2 ) 2 Curtailment loss (1) — — 1 Total benefit cost (gain) $ (2 ) $ (2 ) $ 3 __________________________________________ (1) The curtailment loss for the year ended December 31, 2013 was related to EEI’s other post-employment plan for EEI salaried employees, resulting from a plan amendment and terminations associated with the AER Acquisition
Schedule of Assumptions Used	The following weighted average assumptions were used to determine benefit obligations: Pension Benefits Other Benefits Year Ended December 31, 2015 2014 2015 2014 Discount rate (1) 4.35 % 4.00 % 4.35 % 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, 2015 2014 2013 2015 2014 2013 Discount rate 4.35 % 4.00 % 4.82 % 4.35 % 4.00 % 4.78 % Dynegy - Expected return on plan assets 5.70 % 6.00 % 7.00 % N/A N/A N/A EEI - Expected return on plan assets (1) 6.00 % 6.25 % 6.25 % 5.50 % 6.00 % 6.00 % Rate of compensation increase (2) 3.50 % 3.50 % 3.50 % 3.50 % 3.50 % 3.50 % __________________________________________ (1) The average expected return on EEI’s other post-employment plan assets was 5.50 percent for the year ended December 31, 2015 and 6 percent for the years ended December 31, 2014 and 2013 . The expected return on EEI’s other post-employment plan assets was 6.20 percent for EEI union employees and 4.80 percent for EEI salaried employees for the year ended December 31, 2015 . For the years ended December 31, 2014 and 2013 , the expected return on EEI’s other post-employment plan assets was 6.50 percent for EEI union employees and 5.50 percent for EEI salaried employees. (2) The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2015, 2014 and 2013 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, 2015 2014 2013 Health care cost trend rate assumed for next year 7.00 % 7.25 % 7.75 % Ultimate trend rate 4.50 % 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2023 2023 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 $ 1 $ — Impact on accumulated post-employment benefit obligation $ 9 $ (7 )
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, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ 1 $ 1 $ — $ 2 Equity securities: U.S. companies (1) 32 125 — 157 Non-U.S. companies (2) — 10 — 10 International (3) 8 54 — 62 Fixed income securities (4) 83 152 — 235 Trust asset receivable (5) — 11 — 11 Total $ 124 $ 353 $ — $ 477 Fair Value as of December 31, 2014 (amounts in millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 2 $ — $ 2 Equity securities: U.S. companies (1) 7 142 — 149 Non-U.S. companies (2) — 11 — 11 International (3) 2 53 — 55 Fixed income securities (4) 81 134 — 215 Total $ 90 $ 342 $ — $ 432 ________________________________________ (1) This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market. (2) This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index. (3) This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index. (4) This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds. (5) Relates to the pension and other post-employment plans transferred to Dynegy as a result of the Acquisitions.
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 2016 $ 36 $ 4 2017 $ 36 $ 4 2018 $ 36 $ 4 2019 $ 35 $ 4 2020 $ 36 $ 4 2021 - 2025 $ 183 $ 22

Quarterly Financial Informati49

Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
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 2015 (1) Revenues $ 632 $ 990 $ 1,232 $ 1,016 Operating income (loss) (2) $ (40 ) $ 10 $ 107 $ (13 ) Net income (loss) $ (181 ) $ 386 $ (24 ) $ (134 ) Net income (loss) attributable to Dynegy Inc. common stockholders $ (185 ) $ 382 $ (29 ) $ (140 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic $ (1.49 ) $ 2.98 $ (0.23 ) $ (1.18 ) Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted $ (1.49 ) $ 2.73 $ (0.23 ) $ (1.18 ) 2014 Revenues $ 762 $ 521 $ 615 $ 599 Operating income (loss) $ 1 $ (54 ) $ 22 $ 12 Net loss $ (37 ) $ (122 ) $ (5 ) $ (103 ) Net loss attributable to Dynegy Inc. common stockholders $ (41 ) $ (123 ) $ (5 ) $ (109 ) Net loss per share attributable to Dynegy Inc. common stockholders—Basic and diluted $ (0.41 ) $ (1.23 ) $ (0.05 ) $ (0.91 ) _____________________ (1) The unaudited quarterly information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 reflect the impact of the Acquisitions. Please read Note 3—Acquisitions for further discussion. (2) The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million , respectively. See Note 9—Property, Plant and Equipment for more information.

Condensed Consolidating Finan50

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Consolidating Balance Sheet	Condensed Consolidating Balance Sheet for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 327 $ 94 $ 84 $ — $ 505 Restricted cash — — 39 — 39 Accounts receivable, net 499 1,503 130 (1,730 ) 402 Inventory — 331 266 — 597 Other current assets 26 335 55 (14 ) 402 Total Current Assets 852 2,263 574 (1,744 ) 1,945 Property, Plant and Equipment, Net — 7,813 534 — 8,347 Other Assets Investment in affiliates 13,017 190 — (13,017 ) 190 Other long-term assets 77 133 50 — 260 Goodwill — 797 — — 797 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,963 $ 11,196 $ 1,158 $ (14,778 ) $ 11,539 Current Liabilities Accounts payable $ 1,388 $ 238 $ 396 $ (1,730 ) $ 292 Other current liabilities 95 277 162 (14 ) 520 Total Current Liabilities 1,483 515 558 (1,744 ) 812 Long-term debt 6,370 122 714 — 7,206 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 11,042 954 1,427 (4,803 ) 8,620 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,963 $ 11,196 $ 1,158 $ (14,778 ) $ 11,539 Condensed Consolidating Balance Sheet for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 1,642 $ — $ 54 $ 174 $ — $ 1,870 Restricted cash — 113 — — — 113 Accounts receivable, net 14 — 672 176 (592 ) 270 Inventory — — 88 120 — 208 Other current assets 9 6 125 73 — 213 Total Current Assets 1,665 119 939 543 (592 ) 2,674 Property, Plant and Equipment, Net — — 2,812 443 — 3,255 Other Assets Investment in affiliates 6,133 — — — (6,133 ) — Restricted cash — 5,100 — — — 5,100 Other long-term assets 46 47 53 57 — 203 Intercompany interest receivable 17 — — — (17 ) — Total Assets $ 7,861 $ 5,266 $ 3,804 $ 1,043 $ (6,742 ) $ 11,232 Current Liabilities Accounts payable $ 310 $ 166 $ 112 $ 220 $ (592 ) $ 216 Other current liabilities 51 67 250 97 — 465 Total Current Liabilities 361 233 362 317 (592 ) 681 Long-term debt 1,277 5,100 — 698 — 7,075 Intercompany note payable 3,042 — — 17 (3,059 ) — Other long-term liabilities 158 — 105 190 — 453 Total Liabilities 4,838 5,333 467 1,222 (3,651 ) 8,209 Stockholders’ Equity Dynegy Stockholders’ Equity 3,023 (67 ) 6,379 (179 ) (6,133 ) 3,023 Intercompany note receivable — — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 3,023 (67 ) 3,337 (179 ) (3,091 ) 3,023 Noncontrolling interest — — — — — — Total Equity 3,023 (67 ) 3,337 (179 ) (3,091 ) 3,023 Total Liabilities and Equity $ 7,861 $ 5,266 $ 3,804 $ 1,043 $ (6,742 ) $ 11,232
Condensed Consolidating Income Statement	Condensed Consolidating Statements of Operations for the Year Ended December 31, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,979 $ 895 $ (4 ) $ 3,870 Cost of sales, excluding depreciation expense — (1,485 ) (547 ) 4 (2,028 ) Gross margin — 1,494 348 — 1,842 Operating and maintenance expense — (570 ) (269 ) — (839 ) Depreciation expense — (500 ) (87 ) — (587 ) Impairments — (74 ) (25 ) — (99 ) Gain on sale of assets, net — (1 ) — — (1 ) General and administrative expense (6 ) (91 ) (31 ) — (128 ) Acquisition and integration costs — (124 ) — — (124 ) Operating income (loss) (6 ) 134 (64 ) — 64 Earnings from unconsolidated investments — 1 — — 1 Equity in earnings from investments in affiliates 476 — — (476 ) — Interest expense (475 ) (1 ) (70 ) — (546 ) Other income and expense, net 55 (1 ) — — 54 Income (loss) before income taxes 50 133 (134 ) (476 ) (427 ) Income tax benefit (Note 14) — 471 3 — 474 Net income (loss) 50 604 (131 ) (476 ) 47 Less: Net loss attributable to noncontrolling interest — — (3 ) — (3 ) Net income (loss) attributable to Dynegy Inc. $ 50 $ 604 $ (128 ) $ (476 ) $ 50 Condensed Consolidating Statements of Operations for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ — $ 1,651 $ 846 $ — $ 2,497 Cost of sales, excluding depreciation expense — — (1,065 ) (596 ) — (1,661 ) Gross margin — — 586 250 — 836 Operating and maintenance expense — — (279 ) (198 ) — (477 ) Depreciation expense — — (210 ) (37 ) — (247 ) Gain on sale of assets, net — — 18 — — 18 General and administrative expense (9 ) — (60 ) (45 ) — (114 ) Acquisition and integration costs — — — (35 ) — (35 ) Operating income (loss) (9 ) — 55 (65 ) — (19 ) Bankruptcy reorganization items, net 3 — — — — 3 Earnings from unconsolidated investments — — 10 — — 10 Equity in losses from investments in affiliates (131 ) — — — 131 — Interest expense (89 ) (67 ) — (68 ) 1 (223 ) Other income and expense, net (39 ) — 1 — (1 ) (39 ) Income (loss) before income taxes (265 ) (67 ) 66 (133 ) 131 (268 ) Income tax benefit (expense) (Note 14) (8 ) — — 9 — 1 Net income (loss) (273 ) (67 ) 66 (124 ) 131 (267 ) Less: Net income attributable to noncontrolling interest — — — 6 — 6 Net income (loss) attributable to Dynegy Inc. $ (273 ) $ (67 ) $ 66 $ (130 ) $ 131 $ (273 ) Condensed Consolidating Statements of Operations for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 1,398 $ 68 $ — $ 1,466 Cost of sales, excluding depreciation expense — (1,099 ) (46 ) — (1,145 ) Gross margin — 299 22 — 321 Operating and maintenance expense — (293 ) (15 ) — (308 ) Depreciation expense — (213 ) (3 ) — (216 ) Gain on sale of assets, net — 2 — — 2 General and administrative expense (5 ) (90 ) (2 ) — (97 ) Acquisition and integration costs — — (20 ) — (20 ) Operating loss (5 ) (295 ) (18 ) — (318 ) Bankruptcy reorganization items, net — — — — — Earnings from unconsolidated investments — 2 — — 2 Equity in losses from investments in affiliates (315 ) — — 315 — Interest expense (56 ) (36 ) (5 ) — (97 ) Loss on extinguishment of debt (8 ) (3 ) — — (11 ) Other income and expense, net 4 3 — — 7 Loss from continuing operations before income taxes (380 ) (329 ) (23 ) 315 (417 ) Income tax benefit (expense) (Note 14) 21 58 (21 ) — 58 Loss from continuing operations (359 ) (271 ) (44 ) 315 (359 ) Income (loss) from discontinued operations, net of tax (Note 21) 3 (2 ) — 2 3 Net loss (356 ) (273 ) (44 ) 317 (356 ) Less: Net income (loss) attributable to noncontrolling interest — — — — — Net (loss) attributable to Dynegy Inc. $ (356 ) $ (273 ) $ (44 ) $ 317 $ (356 )
Condensed Statement of Comprehensive Income	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 $ 604 $ (131 ) $ (476 ) $ 47 Other comprehensive income (loss) before reclassifications: Actuarial gain (loss) and plan amendments, net of tax of zero (8 ) 2 10 — 4 Amounts reclassified from accumulated other comprehensive income (loss): Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (3 ) — (1 ) — (4 ) Other comprehensive income from investment in affiliates 11 — — (11 ) — Other comprehensive income, net of tax — 2 9 (11 ) — Comprehensive income (loss) 50 606 (122 ) (487 ) 47 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 — (2 ) (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 49 $ 606 $ (120 ) $ (486 ) $ 49 Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (273 ) $ (67 ) $ 66 $ (124 ) $ 131 $ (267 ) Other comprehensive income before reclassifications: Actuarial loss and plan amendments, net of zero tax expense (20 ) — — (16 ) — (36 ) Amounts reclassified from accumulated other comprehensive income (loss): Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense (5 ) — — — — (5 ) Other comprehensive loss from investment in affiliates (16 ) — — — 16 — Other comprehensive loss, net of tax (41 ) — — (16 ) 16 (41 ) Comprehensive income (loss) (314 ) (67 ) 66 (140 ) 147 (308 ) Less: comprehensive income attributable to noncontrolling interest 3 — — 3 (3 ) 3 Total comprehensive income (loss) attributable to Dynegy Inc. $ (317 ) $ (67 ) $ 66 $ (143 ) $ 150 $ (311 ) Condensed Consolidating Statements of Comprehensive Loss for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (356 ) $ (273 ) $ (44 ) $ 317 $ (356 ) Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of $31 tax expense 53 — 4 — 57 Amounts reclassified from accumulated other comprehensive income (loss): Reclassification of curtailment gain included in net loss, net of tax (7 ) — — — (7 ) Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense (2 ) — — — (2 ) Other comprehensive income from investment in affiliates 4 — — (4 ) — Other comprehensive income, net of tax 48 — 4 (4 ) 48 Comprehensive loss (308 ) (273 ) (40 ) 313 (308 ) Less: comprehensive income attributable to noncontrolling interest 1 — 1 (1 ) 1 Total comprehensive loss attributable to Dynegy Inc. $ (309 ) $ (273 ) $ (41 ) $ 314 $ (309 )
Condensed Consolidating Cash Flow Statement	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 $ (352 ) $ 574 $ (128 ) $ — $ 94 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (13 ) (199 ) (63 ) — (275 ) Decrease in restricted cash 5,148 — — — 5,148 Acquisitions (6,207 ) 29 100 — (6,078 ) Net intercompany transfers 448 — — (448 ) — Distributions from unconsolidated affiliates — 8 — — 8 Other investing — 3 — — 3 Net cash provided by (used in) investing activities (624 ) (159 ) 37 (448 ) (1,194 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of financing costs — 78 19 — 97 Repayments of borrowings (8 ) (23 ) — — (31 ) Financing costs from debt issuances (31 ) — — — (31 ) Financing costs from equity issuances (6 ) — — — (6 ) Dividends paid (23 ) — — — (23 ) Net intercompany transfers — (430 ) (18 ) 448 — Interest rate swap settlement payments (17 ) — — — (17 ) Repurchase of common stock (250 ) — — — (250 ) Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (339 ) (375 ) 1 448 (265 ) Net increase (decrease) in cash and cash equivalents (1,315 ) 40 (90 ) — (1,365 ) Cash and cash equivalents, beginning of period 1,642 54 174 — 1,870 Cash and cash equivalents, end of period $ 327 $ 94 $ 84 $ — $ 505 Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2014 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (70 ) $ (62 ) $ 353 $ (58 ) $ — $ 163 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — — (87 ) (45 ) — (132 ) Proceeds from sales of assets, net — — 18 — — 18 Increase in restricted cash — (5,148 ) — — — (5,148 ) Net intercompany transfers 162 — — — (162 ) — Net cash provided by (used in) investing activities 162 (5,148 ) (69 ) (45 ) (162 ) (5,262 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of preferred stock 400 — — — — 400 Proceeds from issuance of common stock 744 — — — — 744 Proceeds from long-term borrowings — 5,100 12 — — 5,112 Repayments of borrowings (8 ) — (6 ) — — (14 ) Financing costs from debt issuances (1 ) (56 ) — — — (57 ) Financing costs from equity issuances (38 ) — — — — (38 ) Interest rate swap settlement payments (18 ) — — — — (18 ) Net intercompany transfers — 166 (390 ) 62 162 — Other financing (3 ) — — — — (3 ) Net cash provided by (used in) financing activities 1,076 5,210 (384 ) 62 162 6,126 Net increase (decrease) in cash and cash equivalents 1,168 — (100 ) (41 ) — 1,027 Cash and cash equivalents, beginning of period 474 — 154 215 — 843 Cash and cash equivalents, end of period $ 1,642 $ — $ 54 $ 174 $ — $ 1,870 Condensed Consolidating Statements of Cash Flow for the Year Ended December 31, 2013 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (61 ) $ 254 $ (18 ) $ — $ 175 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (97 ) (1 ) — (98 ) Decrease in restricted cash 29 306 — — 335 Acquisitions — — 234 — 234 Net intercompany transfers (1,044 ) — — 1,044 — Other investing — 3 — — 3 Net cash provided by (used in) investing activities (1,015 ) 212 233 1,044 474 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of financing costs 1,753 15 — — 1,768 Repayments of borrowings, including debt extinguishment costs (504 ) (1,413 ) — — (1,917 ) Net intercompany transfers — 1,044 — (1,044 ) — Interest rate swap settlement payments (5 ) — — — (5 ) Net cash provided by (used in) financing activities 1,244 (354 ) — (1,044 ) (154 ) Net increase in cash and cash equivalents 168 112 215 — 495 Cash and cash equivalents, beginning of period 306 42 — — 348 Cash and cash equivalents, end of period $ 474 $ 154 $ 215 $ — $ 843

Restructuring Charges (Tables)

Restructuring Charges (Tables)	12 Months Ended
	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Severance Disclosure	The following table summarizes activity related to liabilities associated with costs related to severance and retention benefits: Year Ended December 31, (amounts in millions) 2015 2014 2013 Beginning of period $ — $ 12 $ 2 Expense (1) 16 3 14 Payments (15 ) (15 ) (4 ) End of period $ 1 $ — $ 12 __________________________________________ (1) Expense during the years ended December 31, 2015, 2014 and 2013 includes $1 million , $1 million and $3 million in retention benefits, respectively.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014 and 2013 is presented below: Segment Data as of and for the Year Ended December 31, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,298 $ 804 $ 1,768 $ — $ 3,870 Intercompany revenues (134 ) (5 ) 139 — — Total revenues $ 1,164 $ 799 $ 1,907 $ — $ 3,870 Depreciation expense $ (138 ) $ (29 ) $ (416 ) $ (4 ) $ (587 ) Impairments (99 ) — — — (99 ) Gain on sale of assets, net — — (1 ) — (1 ) General and administrative expense — — — (128 ) (128 ) Operating income (loss) $ (93 ) $ 49 $ 360 $ (252 ) $ 64 Earnings from unconsolidated investments — — 1 — 1 Interest expense — — — (546 ) (546 ) Other items, net (1 ) — — 55 54 Loss before income taxes (427 ) Income tax benefit — — — 474 474 Net loss 47 Less: Net income attributable to noncontrolling interest (3 ) Net loss attributable to Dynegy Inc. $ 50 Total assets—domestic $ 2,324 $ 897 $ 7,811 $ 507 $ 11,539 Investment in unconsolidated affiliate $ — $ — $ 190 $ — $ 190 Capital expenditures $ (87 ) $ (63 ) $ (112 ) $ (13 ) $ (275 ) Segment Data as of and for the Year Ended December 31, 2014 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 587 $ 850 $ 1,060 $ — $ 2,497 Intercompany revenues 6 (4 ) (2 ) — — Total revenues $ 593 $ 846 $ 1,058 $ — $ 2,497 Depreciation expense $ (51 ) $ (37 ) $ (155 ) $ (4 ) $ (247 ) Gain on sale of assets — — 18 — 18 General and administrative expense — — — (114 ) (114 ) Operating income (loss) $ 40 $ (2 ) $ 79 $ (136 ) $ (19 ) Bankruptcy reorganization items, net — — — 3 3 Earnings from unconsolidated investments — — 10 — 10 Interest expense — — — (223 ) (223 ) Other items, net — — — (39 ) (39 ) Loss from continuing operations before income taxes (268 ) Income tax benefit — — — 1 1 Loss from continuing operations (267 ) Net loss (267 ) Less: Net income (loss) attributable to noncontrolling interest 6 Net loss attributable to Dynegy Inc. $ (273 ) Total assets—domestic $ 1,168 $ 1,039 $ 2,027 $ 6,998 $ 11,232 Capital expenditures $ (39 ) $ (45 ) $ (44 ) $ (4 ) $ (132 ) Segment Data as of and for the Year Ended December 31, 2013 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 469 $ 67 $ 930 $ — $ 1,466 Intercompany revenues (2 ) — 2 — — Total revenues $ 467 $ 67 $ 932 $ — $ 1,466 Depreciation expense $ (50 ) $ (3 ) $ (160 ) $ (3 ) $ (216 ) Gain on sale of assets 2 — — — 2 General and administrative expense — — — (97 ) (97 ) Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 ) Bankruptcy reorganization items, net — — — (1 ) (1 ) Earnings from unconsolidated investments — — 2 — 2 Interest expense — — — (97 ) (97 ) Loss on extinguishment of debt (5 ) — 2 (8 ) (11 ) Other items, net — — 2 6 8 Loss from continuing operations before income taxes (417 ) Income tax benefit — — — 58 58 Loss from continuing operations (359 ) Income from discontinued operations, net of tax — — — 3 3 Net loss (356 ) Less: Net income (loss) attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (356 ) Total assets—domestic $ 1,153 $ 1,190 $ 2,303 $ 645 $ 5,291 Capital expenditures $ (42 ) $ (1 ) $ (53 ) $ (2 ) $ (98 )
Schedule of Revenue by Major Customers by Reporting Segments	Our total revenues for customers which individually accounted for more than 10% of our consolidated revenues, and the segments impacted, for the years ended December 31, 2015, 2014 and 2013 are presented below: Customers Revenues Segment(s) (amounts in millions) 2015 PJM $ 1,088 Coal, IPH, Gas MISO 842 Coal, IPH 2014 MISO $ 836 Coal, IPH NYISO 342 Gas 2013 MISO $ 526 Coal, IPH PJM 275 Gas NYISO 231 Gas CAISO 221 Gas

Organization and Operations (De

Organization and Operations (Details)	12 Months Ended
	Dec. 31, 2015segment
Accounting Policies [Abstract]
Reportable segments	3

Summary of Significant Accoun54

Summary of Significant Accounting Policies - Noncontrolling Interest (Details)	Dec. 31, 2015
Electric Energy, Inc
Noncontrolling Interest [Line Items]
Noncontrolling Interest percentage that we do not own	20.00%

Summary of Significant Accoun55

Summary of Significant Accounting Policies - Other items (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounting Policies [Abstract]
Restricted cash	$ 39	$ 113
Restricted cash classified as long term assets	5,100
Prepaid interest classified as current	$ 113

Summary of Significant Accoun56

Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	$ 8,347		$ 8,347	$ 3,255
Impairment	25	$ 74	99	$ 0	$ 0
Impairment losses related to goodwill			0
Brayton Point Holdings, LLC
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Net	$ 86		86
Impairment			(25)
Wood River
Property, Plant and Equipment [Line Items]
Impairment			$ (74)
Minimum
Property, Plant and Equipment [Line Items]
Useful lives			2 years
Maximum
Property, Plant and Equipment [Line Items]
Useful lives			40 years
Power generation facilities | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			2 years
Power generation facilities | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			36 years
Buildings and improvements | Minimum
Property, Plant and Equipment [Line Items]
Useful lives			2 years
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			3 years
Office and miscellaneous equipment | Maximum
Property, Plant and Equipment [Line Items]
Useful lives			20 years

Summary of Significant Accoun57

Summary of Significant Accounting Policies - Asset Retirement Obligation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Changes in AROs
Balance at beginning of year		$ 224	$ 181
Accretion expense		21	12
Liabilities incurred		4	0
Liabilities settled		(4)	(2)
Revision of previous estimate	[1]	57	(33)
Asset Retirement Obligation, Acquired Obligation	[2]	92	0
Balance at end of year		$ 280	$ 224
[1]	During 2015, we revised our ARO downward by $57 million based on management’s review and assessment of CCR compliance timing and site-specific analysis. During 2014, we revised our ARO upward by $33 million based on observed trends in Illinois, primarily related to CCR surface impoundment closures and landfills in accordance with the standards used in the industry.
[2]	As a result of the Acquisitions in April 2015, the associated AROs were assumed.

Summary of Significant Accoun58

Summary of Significant Accounting Policies - Income Taxes (Details)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Percent of largest amount of benefit upon settlement	50.00%

Acquisitions - Textual (Details

Acquisitions - Textual (Details)	Apr. 02, 2015USD ($)AffiliateFacilitiesMW	Apr. 01, 2015USD ($)FacilitiesMWshares	Dec. 31, 2015USD ($)		Sep. 30, 2015USD ($)		Jun. 30, 2015USD ($)		Mar. 31, 2015USD ($)		Dec. 31, 2014USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Mar. 31, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2025	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2019	Aug. 21, 2014USD ($)	Dec. 02, 2013MW
Business Acquisition [Line Items]
Goodwill			$ 797,000,000								$ 0				$ 797,000,000		$ 797,000,000	$ 0
Acquisition and integration costs																	(124,000,000)	(35,000,000)	$ (20,000,000)
Additional revenues from acquisition			1,016,000,000		$ 1,232,000,000		$ 990,000,000		$ 632,000,000		599,000,000	$ 615,000,000	$ 521,000,000	$ 762,000,000			3,870,000,000	2,497,000,000	1,466,000,000
Operating income (loss)			(13,000,000)	[1]	$ 107,000,000	[1]	10,000,000	[1]	$ (40,000,000)	[1]	$ 12,000,000	$ 22,000,000	$ (54,000,000)	$ 1,000,000			64,000,000	(19,000,000)	(318,000,000)
Bridge Loan
Business Acquisition [Line Items]
Short-term debt			0												0		0
IPH | Operating Segments
Business Acquisition [Line Items]
Additional revenues from acquisition																	799,000,000	846,000,000	67,000,000
Operating income (loss)																	49,000,000	(2,000,000)	(17,000,000)
Gas | Operating Segments
Business Acquisition [Line Items]
Additional revenues from acquisition																	1,907,000,000	1,058,000,000	932,000,000
Operating income (loss)																	360,000,000	79,000,000	7,000,000
Coal | Operating Segments
Business Acquisition [Line Items]
Additional revenues from acquisition																	1,164,000,000	593,000,000	467,000,000
Operating income (loss)																	(93,000,000)	40,000,000	(207,000,000)
Parent
Business Acquisition [Line Items]
Goodwill			0												0		0
Acquisition and integration costs																	0	0	0
Additional revenues from acquisition																	0	0	0
Operating income (loss)																	(6,000,000)	(9,000,000)	(5,000,000)
Brayton Point Holdings, LLC
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)		100.00%
ERC Purchase Agreement
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)		100.00%
Combined cycle gas facilities acquired | Facilities		5
Natural gas power facilities acquired | Facilities		1
Coal-fired power facilities | Facilities		1
ECP Purchase Agreements
Business Acquisition [Line Items]
Indemnification assets, range of outcomes, value, high																					$ 276,000,000
Indemnification assets, amount held in escrow																					104,000,000
EquiPower and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Base purchase price																	6,150,000,000
Equity instruments (3,460,053 common shares of Dynegy)																	105,000,000
Indemnification assets, escrow requirement period		1 year
Goodwill			797,000,000												797,000,000		797,000,000
Acquisition and integration costs																	(86,000,000)	(19,000,000)
Commitment fees																	48,000,000
Business combination revenues																	1,623,000,000
Business combination operating income																	$ 154,000,000
EquiPower and Duke Midwest Acquisitions | Forecast
Business Acquisition [Line Items]
Long-term revenue growth rate																2.50%
Long-term expense growth rate, after year five																				2.50%
EquiPower and Duke Midwest Acquisitions | Maximum | Gas
Business Acquisition [Line Items]
Discount rate																	10.00%
EquiPower and Duke Midwest Acquisitions | Maximum | Coal
Business Acquisition [Line Items]
Discount rate																	13.00%
EquiPower and Duke Midwest Acquisitions | Minimum | Gas
Business Acquisition [Line Items]
Discount rate																	8.00%
EquiPower and Duke Midwest Acquisitions | Minimum | Coal
Business Acquisition [Line Items]
Discount rate																	9.00%
Duke Midwest Purchase Agreement
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)	100.00%
Business Combination, Number of Affiliates | Affiliate	2
Combined cycle gas facilities acquired | Facilities	3
Natural gas power facilities acquired | Facilities	2
Retail energy business acquired | Facilities	1
Power acquired | MW	6,200
Base purchase price	$ 2,800,000,000
Duke Midwest Purchase Agreement | Maximum | Guarantee Obligations
Business Acquisition [Line Items]
Limited guaranty cap of certain obligations	2,800,000,000																				$ 2,800,000,000
Duke Midwest Purchase Agreement | Minimum | Guarantee Obligations
Business Acquisition [Line Items]
Limited guaranty cap of certain obligations	280,000,000
Duke Midwest Acquisition
Business Acquisition [Line Items]
Base purchase price	2,800,000,000
Equity instruments (3,460,053 common shares of Dynegy)	0
Goodwill	$ 0
Duke Midwest Acquisition | Gas
Business Acquisition [Line Items]
Natural gas power facilities acquired | Facilities	5
Duke Midwest Acquisition | Coal
Business Acquisition [Line Items]
Coal-fired power facilities | Facilities	5
Oil-Fired Power Facilities | Facilities	1
Duke Midwest Acquisition | Parent
Business Acquisition [Line Items]
Coal-fired power facilities | Facilities	2
Duke Midwest Acquisition | Third Parties
Business Acquisition [Line Items]
Coal-fired power facilities | Facilities	3
EquiPower Acquisition
Business Acquisition [Line Items]
Combined cycle gas facilities acquired | Facilities		6
Gas and oil power facilities acquired | Facilities		2
Coal-fired power facilities | Facilities		2
Power acquired | MW		6,300
Base purchase price		$ 3,350,000,000
Equity instruments (3,460,053 common shares of Dynegy)		$ 105,000,000
Business combination assets recognized, current intangible assets | shares		3,460,053
Provisional accounting, deferred taxes, net		$ 537,000,000	506,000,000												506,000,000		$ 506,000,000
Deferred tax asset, change in amount							$ 480,000,000								(27,000,000)		453,000,000
Adjustment of deferred tax liability															(31,000,000)
Goodwill		$ 837,000,000	797,000,000												797,000,000		797,000,000
Goodwill, increase (decrease)															(40,000,000)
EquiPower Acquisition | Maximum | Guarantee Obligations
Business Acquisition [Line Items]
Limited guaranty cap of certain obligations			$ 276,000,000												$ 276,000,000		$ 276,000,000
AER Acquisition
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)																						100.00%
Power acquired | MW																						4,062
Deferred tax asset, change in amount																			36,000,000
Acquisition and integration costs																		$ (16,000,000)	$ (20,000,000)
[1]	The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million, respectively. See Note 9—Property, Plant and Equipment for more information.

Acquisitions - Schedule of Asse

Acquisitions - Schedule of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Millions		Apr. 02, 2015	Apr. 01, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Fair value of total consideration transferred	[1]			$ 105	$ 0	$ 7
Liabilities Assumed
Goodwill				797	$ 0
EquiPower and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Cash				6,150
Equity instruments (3,460,053 common shares of Dynegy)				105
Net working capital adjustment				197
Fair value of total consideration transferred				6,452
Assets Acquired
Cash				267
Accounts receivable				176
Inventory				272
Assets from risk management activities (including current portion of $4 million and $30 million, respectively)				37
Prepayments and other current assets				101
Property, plant and equipment				5,507
Investment in unconsolidated affiliate				200
Intangible assets (including current portion of $67 million and $36 million, respectively)				195
Other long-term assets				63
Total assets acquired				6,818
Liabilities Assumed
Accounts payable				124
Accrued liabilities and other current liabilities				32
Debt, current portion				39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)				(164)
Asset retirement obligations				(92)
Intangible liabilities (including current portion of $24 million and $58 million, respectively)				(166)
Deferred income taxes, net				506
Other long-term liabilities				(40)
Total liabilities assumed				(1,163)
Identifiable net assets acquired				5,655
Goodwill				797
Net assets acquired				6,452
Duke Midwest Acquisition
Business Acquisition [Line Items]
Cash		$ 2,800
Equity instruments (3,460,053 common shares of Dynegy)		0
Net working capital adjustment		(9)
Fair value of total consideration transferred		2,791
Assets Acquired
Cash		0
Accounts receivable		127
Inventory		105
Assets from risk management activities (including current portion of $4 million and $30 million, respectively)		33
Prepayments and other current assets		69
Property, plant and equipment		2,734
Investment in unconsolidated affiliate		0
Intangible assets (including current portion of $67 million and $36 million, respectively)		84
Other long-term assets		35
Total assets acquired		3,187
Liabilities Assumed
Accounts payable		97
Accrued liabilities and other current liabilities		10
Debt, current portion		0
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)		(107)
Asset retirement obligations		(49)
Intangible liabilities (including current portion of $24 million and $58 million, respectively)		(93)
Deferred income taxes, net		0
Other long-term liabilities		(40)
Total liabilities assumed		(396)
Identifiable net assets acquired		2,791
Goodwill		0
Net assets acquired		$ 2,791
EquiPower Acquisition
Business Acquisition [Line Items]
Cash			$ 3,350
Equity instruments (3,460,053 common shares of Dynegy)			105
Net working capital adjustment			206
Fair value of total consideration transferred			3,661
Assets Acquired
Cash			267
Accounts receivable			49
Inventory			167
Assets from risk management activities (including current portion of $4 million and $30 million, respectively)			4
Prepayments and other current assets			32
Property, plant and equipment			2,773
Investment in unconsolidated affiliate			200
Intangible assets (including current portion of $67 million and $36 million, respectively)			111
Other long-term assets			28
Total assets acquired			3,631
Liabilities Assumed
Accounts payable			27
Accrued liabilities and other current liabilities			22
Debt, current portion			39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)			(57)
Asset retirement obligations			(43)
Intangible liabilities (including current portion of $24 million and $58 million, respectively)			(73)
Deferred income taxes, net			506
Other long-term liabilities			0
Total liabilities assumed			(767)
Identifiable net assets acquired			2,864
Goodwill			837	$ 797
Net assets acquired			$ 3,661
[1]	Represents the consideration given by us for acquisitions. Please read Note 3—Acquisitions for further discussion.

Acquisitions - Schedule of As61

Acquisitions - Schedule of Assets Acquired and Liabilities Assumed - Non Printing (Details) (Details) - USD ($) $ in Millions	Apr. 01, 2015	Apr. 02, 2015
EquiPower Acquisition
Business Acquisition [Line Items]
Business combination assets recognized, current intangible assets	3,460,053
Business combination assets recognized, current assets from risk management activities	$ 4
Business combination assets recognized, unfavorable contract accrual, current	67
Business combination assets recognized, current liabilities from risk management activities	41
Business combination assets recognized, intangible liabilities, current	$ 24
Duke Midwest Purchase Agreement
Business Acquisition [Line Items]
Business combination assets recognized, current assets from risk management activities		$ 30
Business combination assets recognized, unfavorable contract accrual, current		36
Business combination assets recognized, current liabilities from risk management activities		0
Business combination assets recognized, intangible liabilities, current		$ 58

Acquisitions - Schedule of Pro

Acquisitions - Schedule of Pro Forma Information (Details) - EquiPower and Duke Midwest Acquisitions - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Revenue	$ 4,860	$ 5,574
Net Income (Loss) from continuing operations	308	(613)
Noncontrolling Interest
Business Acquisition [Line Items]
Net Income (Loss) from continuing operations	(3)	6
Dynegy Inc
Business Acquisition [Line Items]
Net Income (Loss) from continuing operations	$ 311	$ (619)

Risk Management Activities, D63

Risk Management Activities, Derivatives and Financial Instruments - Textual (Details)	12 Months Ended
	Dec. 31, 2015
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) warrant in Millions, t in Millions, gal in Millions, dollars in Millions, MWh in Millions, BTU in Millions, $ in Millions		Dec. 31, 2015USD ($)tBTUMWhwarrantgaldollarsshares	Dec. 31, 2014USD ($)
Derivative [Line Items]
Number of Dynegy securities called by each warrant | shares		1
Not Designated as Hedging Instrument
Derivative [Line Items]
Right to reclaim cash, offset		$ 106	$ 9
Not Designated as Hedging Instrument | Future Contracts | Electricity derivatives
Derivative [Line Items]
Purchase (Sales), Quantity | MWh	[1]	45
Asset (Liability) Fair Value	[1],[2]	$ (1)
Not Designated as Hedging Instrument | Future Contracts | Electricity basis derivatives
Derivative [Line Items]
Purchase (Sales), Quantity | MWh	[3]	29
Asset (Liability) Fair Value	[2],[3]	$ 24
Not Designated as Hedging Instrument | Future Contracts | Natural gas derivatives
Derivative [Line Items]
Purchase (Sales), Quantity | BTU	[1]	305
Asset (Liability) Fair Value	[1],[2]	$ (143)
Not Designated as Hedging Instrument | Future Contracts | Natural gas basis derivatives
Derivative [Line Items]
Purchase (Sales), Quantity | BTU		69
Asset (Liability) Fair Value	[2]	$ (7)
Not Designated as Hedging Instrument | Future Contracts | Diesel fuel
Derivative [Line Items]
Purchase (Sales), Quantity | gal		3
Asset (Liability) Fair Value	[2]	$ (4)
Not Designated as Hedging Instrument | Future Contracts | Coal
Derivative [Line Items]
Purchase (Sales), Quantity | t	[4]	0
Asset (Liability) Fair Value	[2],[4]	$ (23)
Derivative, nonmonetay notional mount | t		1
Not Designated as Hedging Instrument | Interest Rate Swaps
Derivative [Line Items]
Purchase (Sales), Quantity | dollars		777
Asset (Liability) Fair Value	[2]	$ (42)
Not Designated as Hedging Instrument | Common stock warrants
Derivative [Line Items]
Purchase (Sales), Quantity | warrant	[5]	16
Asset (Liability) Fair Value	[2]	$ (7)
[1]	Mainly comprised of swaps, options and physical forwards.
[2]	Includes both asset and liability risk management positions, but excludes margin and collateral netting of $106 million.
[3]	Comprised of FTRs and swaps.
[4]	Our net position rounds to less than 1 million tons.
[5]	Each warrant is convertible into one share of Dynegy common stock.

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, 2015	Dec. 31, 2014
Derivative Assets [Abstract]
Derivative Assets, Gross Fair Value	$ 403	$ 115
Derivative Asset, Contract Netting	(285)	(35)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	118	80
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(606)	(268)
Derivative Liability, Contract Netting	285	35
Right to reclaim cash, offset	106	9
Derivative Liabilities, Net Fair Value	(215)	(224)
Total Derivatives, Gross Fair Value	(203)	(153)
Total Derivatives, Contract Netting	0	0
Total Derivatives, Collateral or Margin Received or Paid	106	9
Total Derivatives, Net Fair Value	(97)	(144)
Commodity Contracts | Assets from Risk Management Activities
Derivative Assets [Abstract]
Derivative Assets, Gross Fair Value	403	115
Derivative Asset, Contract Netting	(285)	(35)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	118	80
Commodity Contracts | Liabilities from Risk Management Activities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(557)	(163)
Derivative Liability, Contract Netting	285	35
Right to reclaim cash, offset	106	9
Derivative Liabilities, Net Fair Value	(166)	(119)
Interest Rate Contracts | Liabilities from Risk Management Activities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(42)	(44)
Derivative Liability, Contract Netting	0	0
Right to reclaim cash, offset	0	0
Derivative Liabilities, Net Fair Value	(42)	(44)
Common stock warrants | Other long-term liabilities
Derivative Liabilities [Abstract]
Derivative Liabilities, Gross Fair Value	(7)	(61)
Derivative Liability, Contract Netting	0	0
Right to reclaim cash, offset	0	0
Derivative Liabilities, Net Fair Value	$ (7)	$ (61)

Risk Management Activities, D66

Risk Management Activities, Derivatives and Financial Instruments - Schedule of Collateral Posted and Balance Sheet Location (Details) - Commodity Contracts - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Credit risk derivative liabilities at fair value	$ 49
Derivative liability, fair value of collateral	21
Prepayments and other current assets, Collateral posted
Cash Collateral Posted [Abstract]
Gross collateral posted with counterparties	162	$ 49
Right to reclaim cash, offset	106	9
Net collateral within Prepayments and other current assets	$ 56	$ 40

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Commodity Contracts | Revenues
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	$ 194	$ (183)	$ (101)
Interest Rate Contracts | Interest Expense
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	(15)	(15)	(7)
Common stock warrants | Other Income (Expense), Net
Derivatives Not Designated as Hedges
Impact of gains (losses) recognized in income on derivative financial instruments	$ 54	$ (40)	$ (1)

Fair Value Measurements - Textu

Fair Value Measurements - Textual (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Credit Derivative, Maximum Exposure, Undiscounted	$ 45	$ 12

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, 2015	Dec. 31, 2014
Assets:
Assets from commodity risk management activities:	$ 403	$ 115
Liabilities:
Liabilities from commodity risk management activities:	(557)	(163)
Liabilities from interest rate contracts	(42)	(44)
Total liabilities	(606)	(268)
Electricity derivatives
Assets:
Assets from commodity risk management activities:	348	110
Liabilities:
Liabilities from commodity risk management activities:	(325)	(53)
Natural gas derivatives
Assets:
Assets from commodity risk management activities:	42	3
Liabilities:
Liabilities from commodity risk management activities:	(192)	(100)
Emissions derivatives
Assets:
Assets from commodity risk management activities:		2
Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	(4)	(6)
Crude oil derivatives
Liabilities:
Liabilities from commodity risk management activities:		(3)
Coal derivatives
Assets:
Assets from commodity risk management activities:	13
Liabilities:
Liabilities from commodity risk management activities:	(36)	(1)
Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	(7)	(61)
Level 1
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Liabilities from interest rate contracts	0	0
Total liabilities	(7)	(61)
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 | Emissions derivatives
Assets:
Assets from commodity risk management activities:		0
Level 1 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Crude oil derivatives
Liabilities:
Liabilities from commodity risk management activities:		0
Level 1 | Coal derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	(7)	(61)
Level 2
Assets:
Assets from commodity risk management activities:	358	93
Liabilities:
Liabilities from commodity risk management activities:	(464)	(137)
Liabilities from interest rate contracts	(42)	(44)
Total liabilities	(506)	(181)
Level 2 | Electricity derivatives
Assets:
Assets from commodity risk management activities:	308	88
Liabilities:
Liabilities from commodity risk management activities:	(267)	(27)
Level 2 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	40	3
Liabilities:
Liabilities from commodity risk management activities:	(158)	(100)
Level 2 | Emissions derivatives
Assets:
Assets from commodity risk management activities:		2
Level 2 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	(4)	(6)
Level 2 | Crude oil derivatives
Liabilities:
Liabilities from commodity risk management activities:		(3)
Level 2 | Coal derivatives
Assets:
Assets from commodity risk management activities:	10
Liabilities:
Liabilities from commodity risk management activities:	(35)	(1)
Level 2 | Common stock warrants
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 3
Assets:
Assets from commodity risk management activities:	45	22
Liabilities:
Liabilities from commodity risk management activities:	(93)	(26)
Liabilities from interest rate contracts	0	0
Total liabilities	(93)	(26)
Level 3 | Electricity derivatives
Assets:
Assets from commodity risk management activities:	40	22
Liabilities:
Liabilities from commodity risk management activities:	(58)	(26)
Level 3 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	2	0
Liabilities:
Liabilities from commodity risk management activities:	(34)	0
Level 3 | Emissions derivatives
Assets:
Assets from commodity risk management activities:		0
Level 3 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 3 | Crude oil derivatives
Liabilities:
Liabilities from commodity risk management activities:		0
Level 3 | Coal derivatives
Assets:
Assets from commodity risk management activities:	3
Liabilities:
Liabilities from commodity risk management activities:	(1)	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	12 Months Ended
	Dec. 31, 2015USD ($)BTUMWh
Natural gas derivatives | MillionMMbtu [Member]
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity | BTU	96
Net Fair Value	$ (32,000,000)
Power Forward Contracts | Million MWh
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity | MWh	4	[1]
Net Fair Value	$ (11,000,000)	[1]
Financial Transmission Rights | Million MWh
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity | MWh	24
Net Fair Value	$ (7,000,000)
Coal derivatives | ThousandofTons [Member]
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Quantity | MWh	0
Net Fair Value	$ 2,000,000
Minimum | Natural gas derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value Inputs, Forward Price	1.40
Minimum | Power Forward Contracts
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Basis Spread	5	[1]
Minimum | Financial Transmission Rights
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Forward Price	0
Minimum | Coal derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value Inputs, Forward Price	4.35
Maximum | Natural gas derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value Inputs, Forward Price	1.70
Maximum | Power Forward Contracts
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Basis Spread	7	[1]
Maximum | Financial Transmission Rights
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs, Forward Price	1
Maximum | Coal derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Fair Value Inputs, Forward Price	$ 5.35
[1]	Represents forward financial and physical transactions at illiquid pricing locations.

Fair Value Measurements - Sch71

Fair Value Measurements - Schedule of Changes in Fair Value of Derivatives (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Risk management activities		$ 130	$ (26)	$ (38)
Level 3
Fair Value, Assets and Liabilities, Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(48)	(4)	10	$ 7
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings		42	(8)	(3)
Settlements	[1]	36	(6)	(9)
Risk management activities		42	(8)	(3)
Level 3 | EquiPower and Duke Midwest Acquisitions
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions		(122)
Level 3 | AER Acquisition
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions				15
Level 3 | Electricity derivatives
Fair Value, Assets and Liabilities, Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(18)	(4)	11	5
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings		39	(9)	(4)
Settlements	[1]	1	(6)	(6)
Risk management activities		39	(9)	(4)
Level 3 | Electricity derivatives | EquiPower and Duke Midwest Acquisitions
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions		(54)
Level 3 | Electricity derivatives | AER Acquisition
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions				16
Level 3 | Natural gas derivatives
Fair Value, Assets and Liabilities, Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(32)	0	0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings		3	0	0
Settlements	[1]	28	0	0
Risk management activities		3	0	0
Level 3 | Natural gas derivatives | EquiPower and Duke Midwest Acquisitions
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions		(63)
Level 3 | Natural gas derivatives | AER Acquisition
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions				0
Level 3 | Heat rate derivatives
Fair Value, Assets and Liabilities, Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		0	0	(1)	2
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings		0	1	1
Settlements	[1]	9	0	(3)
Risk management activities		0	1	1
Level 3 | Heat rate derivatives | EquiPower and Duke Midwest Acquisitions
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions		(9)
Level 3 | Heat rate derivatives | AER Acquisition
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions				(1)
Level 3 | Coal derivatives
Fair Value, Assets and Liabilities, Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		2	0	0	$ 0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Total gains (losses) included in earnings		0	0	0
Settlements	[1]	(2)	0	0
Risk management activities		0	$ 0	0
Level 3 | Coal derivatives | EquiPower and Duke Midwest Acquisitions
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions		$ 4
Level 3 | Coal derivatives | AER Acquisition
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Acquisitions				$ 0
[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 Measurements - Sch72

Fair Value Measurements - Schedule of Fair Value of Receivables and Debt (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Prepayments and other current assets, Collateral posted
Fair value of Financial Instruments
Posted collateral for derivatives with counterparties		$ 56	$ 40
Not Designated as Hedging Instrument
Fair value of Financial Instruments
Right to reclaim cash, offset		106	9
Commodity Contracts | Prepayments and other current assets, Collateral posted
Fair value of Financial Instruments
Right to reclaim cash, offset		106	9
Dynegy, Inc | Equipment Financing Agreements
Fair value of Financial Instruments
Unamortized discount		14
Carrying Amount | Dynegy, Inc | Interest Rate Contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest Rate Derivatives, at Fair Value, Net	[1]	42	44
Carrying Amount | Dynegy, Inc | Commodity Contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[2]	(154)	(48)
Carrying Amount | Dynegy, Inc | Common stock warrants | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Financial Liabilities Fair Value Disclosure	[3]	(7)	(61)
Carrying Amount | Dynegy, Inc | 6.75% Senior Notes, due 2019
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(2,100)	(2,100)
Carrying Amount | Dynegy, Inc | Tranche B-2 Term Loan, due 2020 | Secured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[5]	(778)	(785)
Unamortized premiums and discounts		2	3
Carrying Amount | Dynegy, Inc | 7.375% Senior Notes, due 2022
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(1,750)	(1,750)
Carrying Amount | Dynegy, Inc | 5.875% Senior Notes, due 2023 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1]	(500)	(500)
Carrying Amount | Dynegy, Inc | 7.625% Senior Notes, due 2024
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(1,250)	(1,250)
Carrying Amount | Dynegy, Inc | Inventory Financing Agreements | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1]	(136)	(23)
Carrying Amount | Dynegy, Inc | Equipment Financing Agreements
Fair value of Financial Instruments
Long-term debt, gross	[6]	(61)	0
Unamortized discount		14
Carrying Amount | Genco | 7.00% Senior Notes Series H, due 2018 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	(276)	(268)
Carrying Amount | Genco | 6.30% Senior Notes Series I, due 2020 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	(213)	(206)
Carrying Amount | Genco | 7.95% Senior Notes Series F, due 2032 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	(225)	(224)
Unamortized premiums and discounts		111	127
Fair Value | Dynegy, Inc | Interest Rate Contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest Rate Derivatives, at Fair Value, Net	[1]	42	44
Fair Value | Dynegy, Inc | Commodity Contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[2]	(154)	(48)
Fair Value | Dynegy, Inc | Common stock warrants | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Financial Liabilities Fair Value Disclosure	[3]	(7)	(61)
Fair Value | Dynegy, Inc | 6.75% Senior Notes, due 2019
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(1,985)	(2,132)
Fair Value | Dynegy, Inc | Tranche B-2 Term Loan, due 2020 | Secured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[5]	(754)	(775)
Fair Value | Dynegy, Inc | 7.375% Senior Notes, due 2022
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(1,531)	(1,777)
Fair Value | Dynegy, Inc | 5.875% Senior Notes, due 2023 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1]	(404)	(475)
Fair Value | Dynegy, Inc | 7.625% Senior Notes, due 2024
Fair value of Financial Instruments
Long-term debt, gross	[1],[4]	(1,078)	(1,272)
Fair Value | Dynegy, Inc | Inventory Financing Agreements | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1]	(136)	(23)
Fair Value | Dynegy, Inc | Equipment Financing Agreements
Fair value of Financial Instruments
Long-term debt, gross	[6]	(61)	0
Fair Value | Genco | 7.00% Senior Notes Series H, due 2018 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	(204)	(264)
Fair Value | Genco | 6.30% Senior Notes Series I, due 2020 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	(148)	(208)
Fair Value | Genco | 7.95% Senior Notes Series F, due 2032 | Unsecured Debt
Fair value of Financial Instruments
Long-term debt, gross	[1],[7]	$ (162)	$ (241)
[1]	The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels.
[2]	Carrying amount of commodity-based derivative contracts excludes $106 million and $9 million of cash posted as collateral, as of December 31, 2015 and 2014, respectively.
[3]	The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels.
[4]	At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”).
[5]	Carrying amount includes an unamortized discount of $2 million and $3 million as of December 31, 2015 and 2014, respectively. Please read Note 13—Debt for further discussion.
[6]	Carrying amounts for the equipment financing agreements include unamortized discounts of $14 million as of December 31, 2015. In addition, the fair value is classified as Level 3 within the fair value hierarchy levels.
[7]	Combined carrying amounts as of December 31, 2015 and 2014 include unamortized discounts of $111 million and $127 million, respectively. Please read Note 13—Debt for further discussion.

Accumulated Other Comprehensi73

Accumulated Other Comprehensive Income - Changes in AOCI (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning of period		$ 20	[1]	$ 58	[1]	$ 11
Actuarial gain (loss) and plan amendments (net of tax of zero, $31, zero and zero, respectively)		3		(33)		56
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)	[2]	0		0		(7)
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero, zero, and zero, respectively)	[3]	(4)		(5)		(2)
Net current period other comprehensive income (loss), net of tax		(1)		(38)		47
End of period	[1]	$ 19		$ 20		$ 58
[1]	Includes a tax impact of $31 million due to remeasurements of certain of our pension and other post-employment benefit plans in 2013 that will only reverse if and when the Dynegy plans terminate.
[2]	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.
[3]	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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Accumulated Other Comprehensi74

Accumulated Other Comprehensive Income - (AOCI - Phantoms) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Actuarial Gain (Loss) and Plan Amendments		$ 0	$ 0	$ 31
Reclassification of curtailment gain included in net loss, tax	[1]	0	0	0
Amortization of unrecognized prior service credit and actuarial gain, tax	[2]	$ 0	$ 0	$ 0
[1]	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Interest paid (net of amount capitalized)		$ 491	$ 120	$ 92
Taxes received, net		2	0	(1)
Other non-cash investing and financing activity:
Non-cash capital expenditures	[1]	10	23	(3)
Non-cash capital expenditures pursuant to an equipment financing agreement		61	0	0
Fair value of total consideration transferred	[2]	$ 105	$ 0	$ 7
[1]	These expenditures are primarily for changes in our accruals of capital expenditures for all years presented.
[2]	Represents the consideration given by us for acquisitions. Please read Note 3—Acquisitions for further discussion.

Inventory - Summary of invento

Inventory - Summary of inventories (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Materials and supplies		$ 175	$ 83
Coal	[1]	350	119
Fuel oil	[1]	17	3
Emissions allowances	[2]	51	2
Other		4	1
Total		$ 597	$ 208
[1]	At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt—Brayton Point Inventory Financing for further discussion.
[2]	At December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt—Emissions Repurchase Agreements for further discussion.

Inventory - (Inventory Summary

Inventory - (Inventory Summary Footnote) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Inventory [Line Items]
Coal	[1]	$ 350	$ 119
Fuel oil	[1]	17	$ 3
Inventory Financing Agreements
Inventory [Line Items]
Coal		44
Fuel oil		$ 16
[1]	At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2014, there were no amounts that were part of an inventory financing agreement. Please read Note 13—Debt—Brayton Point Inventory Financing for further discussion.

Property, Plant and Equipment

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 9,235	$ 3,685
Accumulated depreciation	(888)	(430)
Property, Plant and Equipment, Net	8,347	3,255
Power generation
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	8,178	3,174
Buildings and improvements
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	956	457
Office and other equipment
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment	$ 101	$ 54

Property, Plant and Equipment79

Property, Plant and Equipment - Total interest costs incurred and interest capitalized for construction in progress (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Abstract]
Total interest costs incurred	$ 487	$ 187	$ 86
Capitalized interest	$ 12	$ 9	$ 2

Property, Plant and Equipment80

Property, Plant and Equipment - Textual (Details) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2015USD ($)	Sep. 30, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Nov. 05, 2015Unit
Property, Plant and Equipment [Line Items]
Impairments	$ (25)	$ (74)	$ (99)	$ 0	$ 0
Property, Plant and Equipment, Net	$ 8,347		8,347	$ 3,255
Wood River
Property, Plant and Equipment [Line Items]
Number of units expected to be retired | Unit						2
Impairments			$ 74
Discount rates for discounting the resulting cash flows	12.00%		12.00%
Brayton Point Holdings, LLC
Property, Plant and Equipment [Line Items]
Impairments			$ 25
Property, Plant and Equipment, Net	$ 86		$ 86
Discount rates for discounting the resulting cash flows	9.00%		9.00%

Joint Ownership of Generating81

Joint Ownership of Generating Facilities - Ownership Interest in Jointly Owned Facilities (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Property, Plant and Equipment		$ 9,235	$ 3,685
Accumulated depreciation		(888)	(430)
Property, Plant and Equipment, Net		$ 8,347	$ 3,255
Miami Fort
Schedule of Equity Method Investments [Line Items]
Ownership Interest		64.00%
Property, Plant and Equipment		$ 207
Accumulated depreciation		(16)
Construction Work in Progress		3
Property, Plant and Equipment, Net		$ 194
Stuart
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	39.00%
Property, Plant and Equipment	[1]	$ 32
Accumulated depreciation	[1]	(4)
Construction Work in Progress	[1]	20
Property, Plant and Equipment, Net	[1]	$ 48
Conesville
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	40.00%
Property, Plant and Equipment	[1]	$ 61
Accumulated depreciation	[1]	(2)
Construction Work in Progress	[1]	4
Property, Plant and Equipment, Net	[1]	$ 63
Zimmer
Schedule of Equity Method Investments [Line Items]
Ownership Interest		46.50%
Property, Plant and Equipment		$ 99
Accumulated depreciation		(10)
Construction Work in Progress		11
Property, Plant and Equipment, Net		$ 100
Killen
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	33.00%
Property, Plant and Equipment	[1]	$ 17
Accumulated depreciation	[1]	(1)
Construction Work in Progress	[1]	2
Property, Plant and Equipment, Net	[1]	$ 18
[1]	Facilities not operated by Dynegy.

Unconsolidated Investments (Det

Unconsolidated Investments (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Apr. 01, 2015MW	Jun. 27, 2014MW
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliate	$ 190	$ 0
Earnings from unconsolidated investments	1	10	$ 2
Distributions from unconsolidated investments	3	0	0
Distributions from unconsolidated affiliates	8	0	$ 0
Accounts receivable, net	402	270
Black Mountain
Schedule of Equity Method Investments [Line Items]
Distributions from unconsolidated affiliates		10
Electrical power capacity divested | MW					85
Net electrical power capacity divested | MW					43
Black Mountain | Sale of Subsidiary Gain (Loss)
Schedule of Equity Method Investments [Line Items]
Noncontrolling interest ownership percentage					50.00%
Proceeds from sale of business interest		$ 17
Elwood
Schedule of Equity Method Investments [Line Items]
Percent of voting interests acquired (as a percentage)				50.00%
Number of power facilities acquired | MW				1,576
Identifiable net assets acquired	89
Earnings from unconsolidated investments	1
Distributions from unconsolidated investments	11
Distributions from unconsolidated affiliates	8
Accounts receivable, net	$ 3

Intangible Assets and Liabili83

Intangible Assets and Liabilities - Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Intangible Assets:
Gross Carrying Amount	$ 306	$ 111
Accumulated Amortization	(142)	(46)
Finite-Lived Intangible Assets, Net	164	65
Intangible Liabilities:
Electricity Contract Liability, Gross	(30)	(20)
Electricity Contract Liability, Accumulated Amortization	19	14
Electricity Contract Liability, Net	(11)	(6)
Coal Contract Liability, Gross	(134)	(41)
Coal Contract Liability, Accumulated Amortization	82	22
Coal Contract Liability, Net	(52)	(19)
Coal Transport Contract Liability, Gross	(104)	(81)
Coal Transport Liability, Accumulated Amortization	64	32
Coal Transport Liability, Net	(40)	(49)
Gas Transport Contract Liability, Gross	(64)	(24)
Gas Transport Liability, Accumulated Amortization	27	17
Gas Transport Liability, Net	(37)	(7)
Intangible Liabilities, Gross	(332)	(166)
Intangible Liabilities, Accumulated Amortization	192	85
Intangible Liabilities, Net	(140)	(81)
Intangible Assets and Liabilities, Net [Abstract]
Intangible Assets (Liabilities), Gross	(26)	(55)
Intangible Assets (Liabilities), Accumulated Amortization	(50)	(39)
Intangible Assets (Liabilities), Net	24	(16)
Electricity contracts
Intangible Assets:
Gross Carrying Amount	260	111
Accumulated Amortization	(126)	(46)
Finite-Lived Intangible Assets, Net	134	65
Gas transport contracts
Intangible Assets:
Gross Carrying Amount	46	0
Accumulated Amortization	(16)	0
Finite-Lived Intangible Assets, Net	$ 30	$ 0

Intangible Assets and Liabili84

Intangible Assets and Liabilities - Amortization of Intangible Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	$ (11)	$ 45	$ 251
Electricity contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	75	96	136
Coal contracts, net
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	(60)	(14)	129
Coal transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	(32)	(29)	(7)
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	$ 6	$ (8)	$ (7)

Intangible Assets and Liabili85

Intangible Assets and Liabilities - Amortization Expense for the Next Five Years of Finite Lived Intangible Assets (Details) $ in Millions	Dec. 31, 2015USD ($)
Intangible Assets, Net (Excluding Goodwill) [Abstract]
2,016	$ 18
2,017	19
2,018	4
2,019	0
2,020	$ (2)

Intangible Assets and Liabili86

Intangible Assets and Liabilities - Schedule of Acquired Intangible Assets (Details) - USD ($) $ in Millions	1 Months Ended
	Apr. 30, 2015	Apr. 02, 2015	Apr. 01, 2015
EquiPower Acquisition
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount			$ 111
Intangible Assets: Weighted-Average Amortization Period	30 months
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount			(73)
Intangible Liabilities, Weighted Average Amortization Period	81 months
Total intangible assets and liabilities, net			38
EquiPower Acquisition | Electricity contracts
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount			68
Intangible Assets: Weighted-Average Amortization Period	31 months
EquiPower Acquisition | Gas transport contracts
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount			43
Intangible Assets: Weighted-Average Amortization Period	28 months
Duke Midwest Purchase Agreement
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount		$ 84
Intangible Assets: Weighted-Average Amortization Period	37 months
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount		(93)
Intangible Liabilities, Weighted Average Amortization Period	27 months
Total intangible assets and liabilities, net		(9)
Duke Midwest Purchase Agreement | Electricity contracts
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount		80
Intangible Assets: Weighted-Average Amortization Period	38 months
Duke Midwest Purchase Agreement | Coal Contracts
Intangible Assets:
Intangible Assets: Weighted-Average Amortization Period	9 months
Duke Midwest Purchase Agreement | Gas transport contracts
Intangible Assets:
Intangible Assets Acquired, Gross Carrying Amount		4
Intangible Assets: Weighted-Average Amortization Period	19 months
Coal derivative contracts | EquiPower Acquisition
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount			(10)
Intangible Liabilities, Weighted Average Amortization Period	21 months
Coal derivative contracts | Duke Midwest Purchase Agreement
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount		(83)
Intangible Liabilities, Weighted Average Amortization Period	27 months
Electricity contracts | Duke Midwest Purchase Agreement
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount		$ (10)
Intangible Liabilities, Weighted Average Amortization Period	23 months
Coal transport contracts | EquiPower Acquisition
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount			(23)
Intangible Liabilities, Weighted Average Amortization Period	22 months
Natural gas contracts | EquiPower Acquisition
Intangible Liabilities:
Intangible Liabilities, Weighted Average Amortization Period	1 month
Gas transport contracts | EquiPower Acquisition
Intangible Liabilities:
Intangible Liabilities Assumed, Gross Carrying Amount			$ (40)
Intangible Liabilities, Weighted Average Amortization Period	128 months

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions		Dec. 31, 2015	Apr. 01, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Long-term debt		$ 7,416		$ 7,236
Unamortized discounts on debt, net		(127)		(130)
Total debt		7,289		7,106
Less: Current maturities, including unamortized discounts, net		83		31
Total Long-term debt		$ 7,206		7,075
6.75% Senior Notes, due 2019
Debt Instrument [Line Items]
Interest rate, stated percentage		6.75%	6.75%
Long-term debt	[1]	$ 2,100		2,100
Tranche B-2 Term Loan, due 2020
Debt Instrument [Line Items]
Long-term debt		$ 780		788
7.375% Senior Notes, due 2022
Debt Instrument [Line Items]
Interest rate, stated percentage		7.375%	7.375%
5.875% Senior Notes, due 2023
Debt Instrument [Line Items]
Interest rate, stated percentage		5.875%
7.625% Senior Notes, due 2024
Debt Instrument [Line Items]
Interest rate, stated percentage		7.625%	7.625%
7.00% Senior Notes Series H, due 2018
Debt Instrument [Line Items]
Interest rate, stated percentage		7.00%
6.30% Senior Notes Series I, due 2020
Debt Instrument [Line Items]
Interest rate, stated percentage		6.30%
7.95% Senior Notes Series F, due 2032
Debt Instrument [Line Items]
Interest rate, stated percentage		7.95%
Dynegy, Inc | 7.375% Senior Notes, due 2022
Debt Instrument [Line Items]
Long-term debt	[1]	$ 1,750		1,750
Dynegy, Inc | 5.875% Senior Notes, due 2023
Debt Instrument [Line Items]
Long-term debt		500		500
Dynegy, Inc | 7.625% Senior Notes, due 2024
Debt Instrument [Line Items]
Long-term debt	[1]	1,250		1,250
Dynegy, Inc | Revolving Facility
Debt Instrument [Line Items]
Long-term debt		0		0
Dynegy, Inc | Inventory Financing Agreements
Debt Instrument [Line Items]
Long-term debt		136		23
Dynegy, Inc | Equipment Financing Agreements
Debt Instrument [Line Items]
Long-term debt		75		0
Total debt	[2]	(61)
Genco | 7.00% Senior Notes Series H, due 2018
Debt Instrument [Line Items]
Long-term debt		300		300
Genco | 6.30% Senior Notes Series I, due 2020
Debt Instrument [Line Items]
Long-term debt		250		250
Genco | 7.95% Senior Notes Series F, due 2032
Debt Instrument [Line Items]
Long-term debt		$ 275		$ 275
[1]	At December 31, 2014, these debt agreements were held by Dynegy Finance I, Inc. and Dynegy Finance II, Inc. Upon the closing of the Acquisitions, the Dynegy Finance I and Dynegy Finance II notes were exchanged for an equal aggregate principal amount of notes with the same terms issued by Dynegy (the “Notes”).
[2]	Carrying amounts for the equipment financing agreements include unamortized discounts of $14 million as of December 31, 2015. In addition, the fair value is classified as Level 3 within the fair value hierarchy levels.

Debt - Textual (Details)

Debt - Textual (Details)

Apr. 02, 2015USD ($)

Apr. 01, 2015USD ($)

Mar. 27, 2015USD ($)

Oct. 27, 2014USD ($)

Apr. 23, 2013

Feb. 28, 2015USD ($)

Oct. 31, 2014USD ($)

Sep. 30, 2014

Dec. 31, 2015USD ($)tranche

Aug. 20, 2015USD ($)

Aug. 14, 2015USD ($)

Jan. 29, 2015USD ($)

Dec. 31, 2014USD ($)

Sep. 18, 2014USD ($)

Mar. 31, 2014USD ($)

Dec. 31, 2013USD ($)Agreement

Dec. 02, 2013USD ($)

Long-term Debt, Fiscal Year Maturity [Abstract]

2,016

$ 83,000,000

2,017

55,000,000

2,018

359,000,000

2,019

2,116,000,000

2,020

1,012,000,000

Thereafter

3,791,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Restricted payment interest coverage ratio

[1]

1.75%

Additional indebtedness interest coverage ratio

[2]

2.50%

Additional indebtedness debt-to-capital ratio

[2]

60.00%

Number of repurchase agreements | Agreement

2

Carrying amount

7,416,000,000

$ 7,236,000,000

Long-term Debt

$ 7,289,000,000

7,106,000,000

Interest Rate Swaps

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Derivative, average fixed interest rate (as a percentage)

3.19%

Derivative, lower fixed interest rate range (as a percentage)

1.00%

5.875% Senior Notes, due 2023

Long-term Debt, Fiscal Year Maturity [Abstract]

Amount of unsecured senior notes

$ 500,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Interest rate, stated percentage

5.875%

Revolving Facility

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 1,425,000,000

Debt instrument term

5 years

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Line of credit facility, amount outstanding

$ 0

Letters of credit outstanding

$ 420,000,000

Number of tranches | tranche

3

Letter of Credit

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Credit facility optional extension period

1 year

Basis spread on variable rate (as a percentage)

5.00%

Letter of Credit | Macquarie Bank

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 55,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Letters of credit outstanding

$ 55,000,000

Genco Senior Notes Minimum Interest Rate

Long-term Debt, Fiscal Year Maturity [Abstract]

Amount of unsecured senior notes

$ 825,000,000

Term Facilities and Revolving Facility, (The Credit Agreement)

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

2,225,000,000

Term Facilities Tranche B-2

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

800,000,000

Debt instrument term

7 years

Term Facilities Tranche B-2 | Interest Rate Swaps

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Derivative, notional amount

$ 777,000,000

6.75% Senior Notes, due 2019

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Interest rate, stated percentage

6.75%

6.75%

Carrying amount

[3]

$ 2,100,000,000

2,100,000,000

7.375% Senior Notes, due 2022

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Interest rate, stated percentage

7.375%

7.375%

7.625% Senior Notes, due 2024

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Interest rate, stated percentage

7.625%

7.625%

Illinois Power Marketing

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Letters of credit outstanding

$ 25,000,000

Illinois Power Marketing | Letter of Credit and Reimbursement Agreement

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 25,000,000

$ 25,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Savings deposits

23,000,000

Letters of credit outstanding

20,000,000

Dynegy, Inc | 5.875% Senior Notes, due 2023

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

500,000,000

500,000,000

Dynegy, Inc | Inventory Financing Agreements

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

136,000,000

23,000,000

Dynegy, Inc | Revolving Facility

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

0

0

Dynegy, Inc | Equipment Financing Agreements

Long-term Debt, Fiscal Year Maturity [Abstract]

Unamortized discount

14,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

75,000,000

0

Long-term Debt

[4]

(61,000,000)

Dynegy, Inc | 7.375% Senior Notes, due 2022

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

[3]

1,750,000,000

1,750,000,000

Dynegy, Inc | 7.625% Senior Notes, due 2024

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Carrying amount

[3]

1,250,000,000

$ 1,250,000,000

CCA Repurchase Agreement

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Assets repurchased under agreement to repurchase

$ 6,000,000

Assets sold under agreements to repurchase, carrying amount

$ 6,000,000

RGGI Repurchase Agreement

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Assets repurchased under agreement to repurchase

$ 23,000,000

Assets sold under agreements to repurchase, carrying amount

78,000,000

$ 20,000,000

$ 58,000,000

$ 12,000,000

$ 11,000,000

Assets sold under agreements to repurchase, carry rate

3.31%

3.56%

Revolving Facility | Illinois Power Marketing

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Credit facility tenor

2 years

Unsecured Debt | Dynegy Finance II, Inc | Senior Notes

Long-term Debt, Fiscal Year Maturity [Abstract]

Proceeds from issuance of debt

$ 3,060,000,000

Unsecured Debt | Dynegy Finance I, Inc | Senior Notes

Long-term Debt, Fiscal Year Maturity [Abstract]

Proceeds from issuance of debt

$ 2,040,000,000

Duke Midwest Purchase Agreement

Long-term Debt, Fiscal Year Maturity [Abstract]

Debt instrument term

5 years

Duke Midwest Purchase Agreement | Revolving Facility | Tranche maturing on April 02, 2020

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 600,000,000

EquiPower Acquisition

Long-term Debt, Fiscal Year Maturity [Abstract]

Debt instrument term

5 years

EquiPower Acquisition | Inventory Financing Agreements

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 15,000,000

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Letters of credit outstanding

$ 58,000,000

EquiPower Acquisition | Revolving Facility | Tranche maturing on April 23, 2018

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

475,000,000

EquiPower Acquisition | Revolving Facility | Tranche maturing on April 01, 2020

Long-term Debt, Fiscal Year Maturity [Abstract]

Maximum borrowing capacity

$ 350,000,000

LIBOR | Line of Credit

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Basis spread on variable rate (as a percentage)

5.60%

Line of credit facility, commitment fee (as a percentage)

0.75%

LIBOR | Duke Midwest Purchase Agreement

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Basis spread on variable rate (as a percentage)

2.75%

LIBOR | EquiPower Acquisition

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Basis spread on variable rate (as a percentage)

2.75%

Base Rate | Duke Midwest Purchase Agreement

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Basis spread on variable rate (as a percentage)

1.75%

Base Rate | EquiPower Acquisition

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Basis spread on variable rate (as a percentage)

1.75%

Coal | Inventory Financing Agreements

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Inventory financing, debt obligation increase (as a percentage)

85.00%

Inventory financing, line of credit increase (as a percentage)

15.00%

Fuel Oils | Inventory Financing Agreements

Debt Instrument, Covenant Compliance, Ratios [Abstract]

Inventory financing, debt obligation increase (as a percentage)

90.00%

Inventory financing, line of credit increase (as a percentage)

10.00%

[1]

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

[2]

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

[3]

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

[4]

Carrying amounts for the equipment financing agreements include unamortized discounts of $14 million as of December 31, 2015. In addition, the fair value is classified as Level 3 within the fair value hierarchy levels.

Income Taxes - Narratives (Deta

Income Taxes - Narratives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Contingency [Line Items]
Income (loss) from continuing operations before income taxes	$ (427)	$ (268)	$ (417)
Effective tax rate (percent)	111.00%	0.00%	14.00%
Unrecognized tax benefits, that if recognized would impact effective tax rate	$ 3
Deferred tax asset, alternative minimum tax credit	26
State and Local Jurisdiction
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	3,100
Internal Revenue Service (IRS) [Member]
Income Tax Contingency [Line Items]
Operating Loss Carryforwards	$ 3,900

Income Taxes - Current and Defe

Income Taxes - Current and Defered Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current tax expense	$ (3)	$ 0	$ (9)
Deferred tax benefit	477	1	67
Income tax benefit	$ 474	$ 1	$ 58

Income Taxes - Reconcilliation

Income Taxes - Reconcilliation of Income Tax Benefit (Details) - USD ($) $ in Millions		3 Months Ended	6 Months Ended	12 Months Ended
		Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Investments, Owned, Federal Income Tax Note [Line Items]
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Other, Amount				$ 18	$ (14)
Federal statutory income tax rate, percent				35.00%	35.00%	35.00%
Expected tax benefit at U.S. statutory rate				$ 149	$ 94	$ 146
State taxes				68	0	3
Permanent differences	[1]			16	(15)	2
Valuation allowance	[2],[3],[4]			271	(331)	(22)
Uncertain tax position				0	244	(67)
Unconsolidated subsidiary adjustment				0	5	0
Adjustment to AMT credits				(26)	0	0
Other				(4)	4	(4)
Income tax benefit				474	1	58
Decrease due to settlements and payments				1	$ 270	0
AER Acquisition
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred tax asset, change in amount						$ 36
EquiPower Acquisition
Investments, Owned, Federal Income Tax Note [Line Items]
Deferred tax asset, change in amount		$ 480	$ (27)	$ 453
[1]	Permanent items for 2015 and 2014 included an $18 million benefit and $14 million expense, respectively, for the change in the fair value of warrants during the year that were not deductible for income taxes.
[2]	On April 14, 2014, we received final notice from the Internal Revenue Service (“IRS”) that their audit of our 2012 tax year has been completed. In accordance with accounting guidance in ASC 740, Income Taxes (“ASC 740”), we recognized $270 million of net tax benefits for tax positions included in the 2012 tax return that had not previously met the “more likely than not” recognition threshold. These benefits were recognized in the second quarter of 2014 as a discrete item with a corresponding adjustment to the valuation allowance.
[3]	Pre-tax income from components other than continuing operations provided a source of income that allowed for the reduction of the valuation allowance from continuing operations the year ended December 31, 2013.
[4]	The AER Acquisition in 2013 caused a change in the attributes and impacted our estimate of the realizability of our deferred tax assets. As a result, we recorded a $36 million reduction to our valuation allowance in connection with the AER Acquisition. In addition, 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.

Income Taxes - Deferred Tax Ass

Income Taxes - Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred tax assets:
Reserves (legal, environmental and other)	$ 0	$ 5
Intangible contracts and other	0	44
Derivative contracts	0	28
Other	0	9
Subtotal	0	86
Less: valuation allowance	0	(72)
Total current deferred tax assets	0	14
Deferred tax liabilities:
Derivative contracts	0	(23)
Other	0	(11)
Total current deferred tax liabilities	0	(34)
Net current deferred tax liabilities	0	(20)
Deferred tax assets:
NOL carryforwards	1,533	1,305
AMT and state tax credit carryforwards	275	280
Reserves (legal, environmental and other)	17	6
Pension and other post-employment benefits	16	20
Asset retirement obligations	89	81
Deferred financing costs and intangible/other contracts	64	40
Derivative contracts	69	14
Other	27	14
Subtotal	2,090	1,760
Less: valuation allowance	(1,276)	(1,463)
Total non-current deferred tax assets	814	297
Deferred tax liabilities:
Depreciation and other property differences	(738)	(209)
Deferred financing costs and power contracts	0	0
Investment in un-consolidated partnership	(27)	0
Derivative contracts	(4)	(14)
Other	(74)	(54)
Total non-current deferred tax liabilities	(843)	(277)
Deferred income taxes	(29)	0
Net non-current deferred tax assets (liabilities)	0	(20)
Net deferred tax liability	$ (29)	$ 0

Income Taxes - Changes in Valua

Income Taxes - Changes in Valuation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 1,535	$ 1,149	$ 1,121
Balance at End of Period	1,276	1,535	1,149
Charged to Costs and Expenses
Movement in Valuation Allowances and Reserves [Roll Forward]
Deferred tax asset, change in amount	(259)	370	28
Charged to Other Accounts
Movement in Valuation Allowances and Reserves [Roll Forward]
Deferred tax asset, change in amount	0	16	0
Additions/ (Deductions)
Movement in Valuation Allowances and Reserves [Roll Forward]
Deferred tax asset, change in amount	$ 0	$ 0	$ 0

Income Taxes - Unrecognized Tax

Income Taxes - Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits [Roll Forward]
Unrecognized tax benefits, beginning of period	$ 4	$ 274	$ 1
Increase based on tax positions related to the prior period	0	0	273
Decrease due to settlements and payments	(1)	(270)	0
Unrecognized tax benefits, end of period	$ 3	$ 4	$ 274

Earnings (Loss) Per Share - Rec

Earnings (Loss) Per Share - Reconciliation of Basic Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Loss from continuing operations		$ 47	$ (267)	$ (359)
Less: Net income attributable to noncontrolling interest		(3)	6	0
Income (loss) from continuing operations attributable to Dynegy Inc.		50	(273)	(359)
Less: Dividends on preferred stock		22	5	0
Income (Loss) from Continuing Operations Available to Common Stockholders, Basic and Diluted		28	(278)	(359)
Loss from continuing operations attributable to Dynegy Inc. common stockholders		$ 28	$ (278)	$ (356)
Basic shares outstanding (shares)		125	105	100
Effect of dilutive securities		1	0	0
Diluted shares outstanding (shares)		126	105	100
Income (loss) from continuing operations (in dollars per share)	[1]	$ 0.22	$ (2.65)	$ (3.59)
[1]	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the years ended December 31, 2014 and 2013.

Earnings (Loss) Per Share - Ant

Earnings (Loss) Per Share - Anti-dilutive shares - potentially dilutive in future (Details) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	29	22.3	17.4
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	0.5	1.4	1
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	0	1	0.7
Performance stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	0	0.3	0.1
Warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share (shares)	15.6	15.6	15.6
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 (shares)	12.9	4	0

Commitments and Contingencies -

Commitments and Contingencies - Legal Proceedings (Details) $ in Millions	Dec. 16, 2014USD ($)	Sep. 30, 2010USD ($)	Jun. 30, 2007USD ($)	Dec. 31, 2015state
Pending Litigation | Gas Index Pricing Litigation
Loss Contingencies [Line Items]
Number of states in which entity operates | state				3
Pending Litigation | Illinova Generating Company Arbitration | Illinova Generating Company
Loss Contingencies [Line Items]
Payments for legal settlements			$ 17
Judicial Ruling | Illinova Generating Company Arbitration | Illinova Generating Company
Loss Contingencies [Line Items]
Damages awarded	$ 2.5	$ 17

Commitments and Contingencies98

Commitments and Contingencies - Other Commitments and Contingencies (Details) $ in Millions	Apr. 02, 2012USD ($)	Jul. 31, 2013USD ($)	Sep. 30, 2013Agreement	Dec. 31, 2015USD ($)Agreement$ / MWh	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2012surface_impoundmentlocalized_area	May. 31, 2015complaint
Loss Contingencies [Line Items]
Estimated minimum number of years CSA commitments will be in effect				15 years
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,016				$ 5
2,017				5
2,018				5
2,019				5
2,020				5
Rental expense				5	$ 5	$ 6
Number of charter party agreements expiring in next fiscal year | Agreement			1
Dynegy's CSA Commitment
Loss Contingencies [Line Items]
Minimum purchase obligations				356
Counterparty's CSA Commitment
Loss Contingencies [Line Items]
Minimum purchase obligations				431
Gas Purchase Commitments
Loss Contingencies [Line Items]
Minimum purchase obligations				254
Transportation of Natural Gas
Loss Contingencies [Line Items]
Minimum purchase obligations				205
Coal
Loss Contingencies [Line Items]
Minimum purchase obligations				1,447
Coal Transportation
Loss Contingencies [Line Items]
Minimum purchase obligations				904
Capital Addition Purchase Commitments
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted				102
VLGC Guarantee
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Other Commitment, Due in next twelve months				$ 11
Number of charter party agreements in aggregate | Agreement				2
Charter agreement extension terms				1 year
Limestone purchase commitments
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted				$ 48
Alternative Energy Interconnect Systems [Member]
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted				23
Other Agreements
Loss Contingencies [Line Items]
Guarantor obligations, maximum exposure, undiscounted				$ 28
MISO 2015-2016 Planning Resource Auction
Loss Contingencies [Line Items]
Pending number of claims | complaint								3
Loss Contingency, Actions Taken by FERC, 2016 and 2017 Planning Reserve Auction, Initial Reference Level for Capacity Per Day | $ / MWh				0
MISO 2015-2016 Planning Resource Auction | Pending Litigation
Loss Contingencies [Line Items]
Pending number of claims | complaint								1
Baldwin Groundwater, Environmental Protection Agency Regulations Compliance, Coal Combustion Residues
Loss Contingencies [Line Items]
Number of localized areas where groundwater standards were exceeded | localized_area							2
Vermillion Facility, Old East and North Sites
Loss Contingencies [Line Items]
Number of localized areas where groundwater standards were exceeded | surface_impoundment							2
Estimated cost for recommended closure alternative for impoundments	$ 10
Hennepin West Ash Pond System
Loss Contingencies [Line Items]
Post-closure monitoring costs		$ 5
Illinois Pollution Control Board | Newton Facility
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Estimated capital costs to comply with existing and known federal and state air emissions regulations				$ 186
Environmental Obligations, Period of Significant Capital Expenditure or Increased Operating Costs				4 years

Commitments and Contingencies99

Commitments and Contingencies - Indemnifications and Guarantees (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Apr. 02, 2015	Aug. 21, 2014
Other Indemnities
Loss Contingencies [Line Items]
Amount of accrued indemnifications, if any	$ 0
EquiPower Acquisition | Maximum | Guarantee Obligations
Loss Contingencies [Line Items]
Guarantee cap of certain obligations	276,000,000
Duke Midwest Purchase Agreement | Other Indemnities
Loss Contingencies [Line Items]
Amount of accrued indemnifications, if any	$ 0
Duke Midwest Purchase Agreement | Maximum | Guarantee Obligations
Loss Contingencies [Line Items]
Guarantee cap of certain obligations		$ 2,800,000,000	$ 2,800,000,000
Covenants, Representations and Warranties | Purchase Commitment | EquiPower Acquisition | Guarantee Obligations
Loss Contingencies [Line Items]
Indemnification obligation term	1 year
Covenants, Representations and Warranties | Purchase Commitment | Duke Midwest Purchase Agreement | Guarantee Obligations
Loss Contingencies [Line Items]
Indemnification obligation term	1 year
Fundamental Representations | EquiPower Acquisition | Guarantee Obligations
Loss Contingencies [Line Items]
Indemnification obligation term	2 years
Fundamental Representations | Duke Midwest Purchase Agreement | Guarantee Obligations
Loss Contingencies [Line Items]
Indemnification obligation term	3 years
Tax Matters, Additional Guarantee Beyond Statute of Limitations | Duke Midwest Purchase Agreement | Guarantee Obligations
Loss Contingencies [Line Items]
Indemnification obligation term	30 days

Capital Stock - Textual (Detail

Capital Stock - Textual (Details) - USD ($)	Apr. 01, 2015	Mar. 03, 2015	Jan. 15, 2015	Nov. 13, 2014	Oct. 14, 2014	Oct. 01, 2012	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Aug. 03, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, shares authorized							20,000,000	20,000,000
Preferred stock, par value (in dollars per share)							$ 0.01	$ 0.01
Financing costs from equity issuances							$ 6,000,000	$ 38,000,000	$ 0
Class of warrant or right, outstanding						15,600,000
Cash dividends							$ 0
Preferred stock, series A 5.375%							5.375%	5.375%
Dividends paid							$ 23,000,000	$ 0	0
Warrants to purchase shares of common stock							$ 40
Common stock, shares authorized						420,000,000	420,000,000	420,000,000
Common stock, par value (in dollars per share)						$ 0.01	$ 0.01	$ 0.01
Term of warrants							5 years
Equivalent value of warrant on determination date, when warrant is underwater							$ 0.01
Fair value of warrants when they are under water							$ 150,000
Authorized shares (in shares)							6,100,000
Limit, shares of common stock subject to options, restricted stock awards, stock unit awards, stock appreciation rights, phantom stock awards and performance awards, denominated in shares							1,200,000
Limit, maximum amount of fair value compensation that may be paid under all performance awards denominated in cash granted to any one individual							$ 10,000,000
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period							10 years
Compensation expense							$ 28,000,000	$ 19,000,000	15,000,000
Tax benefit from compensation expense							10,000,000	7,000,000	5,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized							$ 25,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition							2 years 6 months
Total fair value of shares vested							$ 18,000,000	14,000,000	5,000,000
Cash received from option exercises							500,000	1,000,000	2,000,000
Additional tax deduction from share-based payment awards, less than							$ 1,000,000	1,000,000	$ 1,000,000
Stock Repurchase Program, Authorized Amount										$ 250,000,000
Treasury Stock, Shares, Acquired							11,326,122
Stock Repurchased During Period, Value							$ 250,000,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option exercise price (dollars per share)							$ 18.70
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option exercise price (dollars per share)							$ 32.56
Series A 5.375% mandatory convertible preferred stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred stock, par value (in dollars per share)					$ 0.01
Stock issued during the period					4,000,000		4,000,000
Shares issued, price per share					$ 100
Preferred stock, liquidation preference per share					$ 100
Preferred stock, liquidation preference, value					$ 400,000,000
Issuance of new equity interests					400,000,000			400,000,000
Financing costs from equity issuances					$ 13,000,000
Preferred stock, series A 5.375%					5.375%
Preferred stock, dividends per share, declared		$ 1.34	$ 1.64
Preferred stock dividends		$ 5,000,000	$ 7,000,000
Convertible preferred stock, shares issued upon conversion							2.5806
Stock Repurchased During Period, Value							$ 0
Series A 5.375% mandatory convertible preferred stock | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Convertible preferred stock, shares issued upon conversion							2.5806
Series A 5.375% mandatory convertible preferred stock | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Convertible preferred stock, shares issued upon conversion							3.2258
Series A 5.375% mandatory convertible preferred stock | Over-Allotment Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Sale of stock, underwriter option, period					30 days
Sale of stock, underwriter option, shares					600,000
Common Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during the period				1,500,000	22,500,000	100,202,036
Shares issued, price per share					$ 31
Issuance of new equity interests				$ 744,000,000				$ 0
Stock Repurchased During Period, Value							$ 0
Common Stock | Over-Allotment Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock issued during the period				3,375,000
Sale of stock, underwriter option, period				30 days
EquiPower Acquisition
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Equity interests issued and issuable	$ 105,000,000
Business combination assets recognized, current intangible assets	3,460,053

Capital Stock - Stock Option Ac

Capital Stock - Stock Option Activity (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Outstanding at beginning of period (shares)	1,372
Granted (shares)	485
Exercised (shares)	(25)
Outstanding at end of period (shares)	1,832	1,372
Vested and unvested expected to vest (shares)	1,832
Exercisable at end of period (shares)	945
Outstanding at beginning of period (dollars per share)	$ 21.15
Granted, Weighted Average Exercise Price (dollars per share)	27.43	$ 23.03	$ 22.84
Exercised, Weighted Average Exercise Price (dollars per share)	20.93
Outstanding at end of period (dollars per share)	22.81	$ 21.15
Vested and unvested expected to vest, Weighted Average Exercise Price (dollars per share)	22.81
Exercisable at end of period, Weighted Average Exercise Price (dollars per share)	$ 20.38
Weighted Average Remaining Contractual Life, Outstanding at end of period	8 years 6 months 15 days
Weighted Average Remaining Contractual Life, Vested and unvested expected to vest	8 years 6 months 15 days
Weighted Average Remaining Contractual Life, Exercisable at end of period	7 years 3 months 8 days
Aggregate Intrinsic Value - Outstanding at end of period	$ 0
Aggregate Intrinsic Value - Vested and unvested expected to vest	0
Aggregate Intrinsic Value - Exercisable at end of period	0
Options exercised in Period, Total Intrinsic Value	$ 1	$ 1

Capital Stock - Black-Scholes M

Capital Stock - Black-Scholes Model, Weighted-Average Assumptions for Grants (Details) - $ / shares		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Dividend Yield		0.00%	0.00%	0.00%
Expected volatility	[1]	27.70%	23.96%	32.79%
Risk-free interest rate	[2]	1.64%	1.61%	1.05%
Expected option life	[3]	5 years 6 months	5 years 6 months	5 years 6 months
Weighted average grant-date fair value of options granted		$ 7.93	$ 5.91	$ 7.35
Duration used to calculated the expected volatility rate				5 years
[1]	For the years ended December 31, 2015 and 2014, the expected volatility was calculated based on the historical volatilities of our stock since October 3, 2012. For the year ended December 31, 2013, the expected volatility was calculated based on five-year historical volatilities of the stock of comparable companies whose shares are traded using daily stock price returns equivalent to the expected term of the options.
[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.

Capital Stock - Activity for Re

Capital Stock - Activity for Restricted and Performance Stock Units (Details) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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)	1,046
Granted (in shares)	878
Vested and released (in shares)	(468)
Forfeited (in shares)	(43)
Outstanding at end of period (in shares)	1,413	1,046
Weighted Average Grant Date Fair Value, Outstanding at beginning of period (in dollars per share)	$ 22.94
Weighted Average Grant Date Fair Value, Granted (in dollars per share)	28.93	$ 23.36	$ 23.15
Weighted Average Grant Date Fair Value, Vested and released (in dollars per share)	22.53
Weighted Average Grant Date Fair Value, Forfeited (in dollars per share)	25.83
Weighted Average Grant Date Fair Value, Outstanding at end of period (in dollars per share)	$ 26.71	$ 22.94
Award vesting period	3 years
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)	304
Granted (in shares)	278
Vested and released (in shares)	0
Forfeited (in shares)	(6)
Outstanding at end of period (in shares)	576	304
Weighted Average Grant Date Fair Value, Outstanding at beginning of period (in dollars per share)	$ 23.13
Weighted Average Grant Date Fair Value, Granted (in dollars per share)	27.54	$ 23.03	$ 23.10
Weighted Average Grant Date Fair Value, Vested and released (in dollars per share)	0
Weighted Average Grant Date Fair Value, Forfeited (in dollars per share)	27.07
Weighted Average Grant Date Fair Value, Outstanding at end of period (in dollars per share)	$ 25.22	$ 23.13
Award vesting period	3 years
Minimum Performance Factor	0.00%
Maximum Performance Factor	200.00%
Negative Total Shareholder Return (TSR), Maximum Performance Factor	100.00%

Employee Compensation, Savin104

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Narratives (Details) - USD ($)		Dec. 02, 2013	Jun. 30, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Contributions by employer				$ 50,000,000	$ 37,000,000	$ 28,000,000
Dynegy, Inc | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations				46.00%
Dynegy, Inc | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations				54.00%
EEI | Equity securities
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations				60.00%
EEI | Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset allocations				40.00%
Phantom Stock Plan
Defined Benefit Plan Disclosure [Line Items]
Compensation expense recognized				$ 1,000,000	4,000,000	5,000,000
Dynegy Inc. 401(K) Savings Plan
Defined Benefit Plan Disclosure [Line Items]
Compensation expense recognized				$ 10,000,000	7,000,000	4,000,000
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	0	0
Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligations				481,000,000	408,000,000
Amortization of prior service credit and net actuarial loss (gain)				1,000,000	2,000,000	1,000,000
Prior service credit				1,000,000	1,000,000	1,000,000
Estimated employer contributions to pension plans for remainder of fiscal year				4,000,000	3,000,000
Service cost				14,000,000	12,000,000	9,000,000
Estimated future employer contributions in next fiscal year				0
Curtailment (gain) loss	[1]			$ 0	0	(7,000,000)
Pension Plans | EEI Other post-employment benefit plan
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year				5.90%
Curtailment (gain) loss		$ 1,000,000
Pension Plans | DYN Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year				5.60%
Curtailment (gain) loss			$ (7,000,000)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligations				$ 74,000,000	95,000,000
Prior service credit				3,000,000	3,000,000	1,000,000
Estimated employer contributions to pension plans for remainder of fiscal year				0
Service cost				1,000,000	1,000,000	1,000,000
Estimated future employer contributions in next fiscal year				2,000,000
Curtailment (gain) loss	[2]			$ 0	$ 0	$ 1,000,000
Other Benefits | Union Employees
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year				6.30%
Other Benefits | Salaried employees
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on assets for next fiscal year				5.75%
[1]	The curtailment gain was related to the DNE pension plan and resulted from the Roseton sale and the termination of a majority of the Danskammer employees.
[2]	The curtailment loss for the year ended December 31, 2013 was related to EEI’s other post-employment plan for EEI salaried employees, resulting from a plan amendment and terminations associated with the AER Acquisition

Employee Compensation, Savin105

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of plan assets, beginning of the year	$ 432
Fair value of plan assets, end of the year	477	$ 432
Pension Benefits
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefit obligation, beginning of the year	408	390
Service cost	14	12	$ 9
Interest cost	18	17	14
Actuarial (gain) loss	(20)	40
Benefits paid	(26)	(37)
Plan change	0	0
Settlements	0	(14)
Benefit obligation, end of the year	483	408	390
Fair value of plan assets, beginning of the year	364	373
Actual return on plan assets	(13)	39
Employer contributions	4	3
Benefits paid	(26)	(37)
Settlements	0	(14)
Fair value of plan assets, end of the year	410	364	373
Funded status	(73)	(44)
Pension Benefits | Duke Midwest Purchase Agreement
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Duke Midwest Acquisition	89	0
Duke Midwest Acquisition	81	0
Other Benefits
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefit obligation, beginning of the year	95	81
Service cost	1	1	1
Interest cost	4	4	2
Actuarial (gain) loss	(12)	15
Benefits paid	(5)	(6)
Plan change	(10)	0
Settlements	(1)	0
Benefit obligation, end of the year	74	95	81
Fair value of plan assets, beginning of the year	68	67
Actual return on plan assets	2	5
Employer contributions	0	0
Benefits paid	(5)	(6)
Settlements	0	0
Fair value of plan assets, end of the year	67	68	$ 67
Funded status	(7)	(27)
Other Benefits | Fair Value
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Benefits paid	(3)	(4)
Benefits paid	(3)	(4)
Other Benefits | Duke Midwest Purchase Agreement
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Duke Midwest Acquisition	2	0
Duke Midwest Acquisition	$ 0	$ 0

Employee Compensation, Savin106

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, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current assets	$ 5	$ 1
Current liabilities	0	0
Non-current liabilities	(78)	(45)
Net amount recognized	(73)	(44)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Non-current assets	23	15
Current liabilities	(2)	(2)
Non-current liabilities	(28)	(40)
Net amount recognized	$ (7)	$ (27)

Employee Compensation, Savin107

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Pre-tax Amounts Recognized in AOCI (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Prior service credit	$ (11)	$ (12)
Actuarial loss (gain)	6	21
Net gain recognized	(17)	(33)
Prior service cost	(1)
Actuarial gain	0
Net gain recognized	(1)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Prior service credit	(34)	(27)
Actuarial loss (gain)	(2)	(12)
Net gain recognized	(32)	$ (15)
Prior service cost	(4)
Actuarial gain	0
Net gain recognized	$ (4)

Employee Compensation, Savin108

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 14	$ 12	$ 9
Interest cost		18	17	14
Expected return on plan assets		(23)	(21)	(19)
Prior service credit		(1)	(1)	(1)
Actuarial loss (gain)		0	(1)	0
Net periodic benefit cost		8	6	3
Curtailment loss	[1]	0	0	(7)
Total benefit cost (gain)		8	6	(4)
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost		1	1	1
Interest cost		4	4	2
Expected return on plan assets		(4)	(4)	0
Prior service credit		(3)	(3)	(1)
Net periodic benefit cost		(2)	(2)	2
Curtailment loss	[2]	0	0	1
Total benefit cost (gain)		$ (2)	$ (2)	$ 3
[1]	The curtailment gain was related to the DNE pension plan and resulted from the Roseton sale and the termination of a majority of the Danskammer employees.
[2]	The curtailment loss for the year ended December 31, 2013 was related to EEI’s other post-employment plan for EEI salaried employees, resulting from a plan amendment and terminations associated with the AER Acquisition

Employee Compensation, Savin109

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, 2015	Dec. 31, 2014		Dec. 31, 2013
Pension Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	[1]	4.35%	4.00%
Rate of compensation increase	[2]	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		4.35%	4.00%		4.82%
Expected return on plan assets		5.70%	6.00%		7.00%
Rate of compensation increase	[3]	3.50%	3.50%		3.50%
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	[4]	6.00%	6.25%		6.25%
Other Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	[1]	4.35%	4.00%
Rate of compensation increase	[2]	3.50%	3.50%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate		4.35%	4.00%		4.78%
Rate of compensation increase	[3]	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		5.50%	6.00%	[4]	6.00%	[4]
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		6.20%	6.50%
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		4.80%	5.50%
[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.
[3]	The rate of compensation increase used for other post-employment benefits for the years ended December 31, 2015, 2014 and 2013 is specifically related to the EEI post-employment plans.
[4]	The average expected return on EEI’s other post-employment plan assets was 5.50 percent for the year ended December 31, 2015 and 6 percent for the years ended December 31, 2014 and 2013. The expected return on EEI’s other post-employment plan assets was 6.20 percent for EEI union employees and 4.80 percent for EEI salaried employees for the year ended December 31, 2015. For the years ended December 31, 2014 and 2013, the expected return on EEI’s other post-employment plan assets was 6.50 percent for EEI union employees and 5.50 percent for EEI salaried employees.

Employee Compensation, Savin110

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Assumed Health Care Cost Trend Rates (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]
Health care cost trend rate assumed for next year	7.00%	7.25%	7.75%
Ultimate trend rate	4.50%	4.50%	4.50%
Year that the rate reaches the ultimate trend rate	2,023	2,023	2,023

Employee Compensation, Savin111

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, 2015USD ($)
Compensation and Retirement Disclosure [Abstract]
Aggregate impact on service cost and interest cost, Increase	$ 1
Aggregate impact on service cost and interest cost, Decrease	0
Impact on accumulated post-employment benefit obligation, Increase	9
Impact on accumulated post-employment benefit obligation, Decrease	$ (7)

Employee Compensation, Savin112

Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans - Fair Value Hierarchy of Plan Assets (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		$ 477	$ 432
Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		124	90
Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		353	342
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		2	2
Cash and cash equivalents | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		1	0
Cash and cash equivalents | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets		1	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	[1]	157	149
Equity securities | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[2]	10	11
Equity securities | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[3]	62	55
Equity securities | Level 1 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[1]	32	7
Equity securities | Level 1 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[2]	0	0
Equity securities | Level 1 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[3]	8	2
Equity securities | Level 2 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[1]	125	142
Equity securities | Level 2 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[2]	10	11
Equity securities | Level 2 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[3]	54	53
Equity securities | Level 3 | U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[1]	0	0
Equity securities | Level 3 | Non-U.S. companies
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[2]	0	0
Equity securities | Level 3 | International
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[3]	0	0
Fixed Income Funds
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[4]	235	215
Fixed Income Funds | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[4]	83	81
Fixed Income Funds | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[4]	152	134
Fixed Income Funds | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[4]	0	$ 0
Trust asset receivable
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[5]	11
Trust asset receivable | Level 1
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[5]	0
Trust asset receivable | Level 2
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[5]	11
Trust asset receivable | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair Value of Plan Assets	[5]	$ 0
[1]	This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.
[2]	This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.
[3]	This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.
[4]	This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.
[5]	Relates to the pension and other post-employment plans transferred to Dynegy as a result of the Acquisitions.

Employee Compensation, Savin113

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, 2015USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 36
2,017	36
2,018	36
2,019	35
2,020	36
2021 - 2025	183
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	4
2,017	4
2,018	4
2,019	4
2,020	4
2021 - 2025	$ 22

Quarterly Financial Informat114

Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Revenues	$ 1,016		$ 1,232		$ 990		$ 632		$ 599	$ 615	$ 521	$ 762	$ 3,870	$ 2,497	$ 1,466
Operating income (loss)	(13)	[1]	107	[1]	10	[1]	(40)	[1]	12	22	(54)	1	64	(19)	(318)
Net income (loss)	(134)		(24)		386		(181)		(103)	(5)	(122)	(37)	47	(267)	(356)
Net loss attributable to Dynegy Inc. common stockholders	$ (140)		$ (29)		$ 382		$ (185)		$ (109)	$ (5)	$ (123)	$ (41)	$ 50	$ (273)	$ (356)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Basic (usd per share)	$ (1.18)		$ (0.23)		$ 2.98		$ (1.49)
Net income (loss) per share attributable to Dynegy Inc. common stockholders—Diluted (usd per share)	$ (1.18)		$ (0.23)		$ 2.73		$ (1.49)
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholdersIncome (loss) from continuing operations (in dollars per share)									$ (0.91)	$ (0.05)	$ (1.23)	$ (0.41)	$ 0.22	$ (2.65)	$ (3.56)
Impairment	$ 25		$ 74										$ 99	$ 0	$ 0
[1]	The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million, respectively. See Note 9—Property, Plant and Equipment for more information.

Condensed Consolidating Fina115

Condensed Consolidating Financial Information - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 505	$ 1,870	$ 843	$ 348
Restricted cash	39	113
Accounts receivable, net	402	270
Inventory	597	208
Other current assets	402	213
Total Current Assets	1,945	2,674
Property, Plant and Equipment, Net	8,347	3,255
Investment in affiliates	190	0
Restricted cash	0	5,100
Other long-term assets	180	143
Goodwill	797	0
Intercompany Receivables	0	0
Total Assets	11,539	11,232	5,291
Accounts payable	292	216
Other current liabilities	520	465
Total Current Liabilities	812	681
Debt, long-term portion	7,206	7,075
Intercompany Payable	0	0
Other long-term liabilities	602	453
Total Liabilities	8,620	8,209
Dynegy Stockholders’ Equity	2,921	3,023
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	2,921	3,023
Noncontrolling interest	(2)	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable	2,919	3,023
Total Liabilities and Equity	11,539	11,232
Eliminations
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0
Accounts receivable, net	(1,730)	(592)
Inventory	0	0
Other current assets	(14)	0
Total Current Assets	(1,744)	(592)
Property, Plant and Equipment, Net	0	0
Investment in affiliates	(13,017)	(6,133)
Restricted cash		0
Other long-term assets	0	0
Goodwill	0
Intercompany Receivables	(17)	(17)
Total Assets	(14,778)	(6,742)
Accounts payable	(1,730)	(592)
Other current liabilities	(14)	0
Total Current Liabilities	(1,744)	(592)
Debt, long-term portion	0	0
Intercompany Payable	(3,059)	(3,059)
Other long-term liabilities	0	0
Total Liabilities	(4,803)	(3,651)
Dynegy Stockholders’ Equity	(13,017)	(6,133)
Intercompany note receivable	3,042	3,042
Total Dynegy Stockholders’ Equity	(9,975)	(3,091)
Noncontrolling interest	0	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable	(9,975)	(3,091)
Total Liabilities and Equity	(14,778)	(6,742)
Parent
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	327	1,642	474	306
Restricted cash	0	0
Accounts receivable, net	499	14
Inventory	0	0
Other current assets	26	9
Total Current Assets	852	1,665
Property, Plant and Equipment, Net	0	0
Investment in affiliates	13,017	6,133
Restricted cash		0
Other long-term assets	77	46
Goodwill	0
Intercompany Receivables	17	17
Total Assets	13,963	7,861
Accounts payable	1,388	310
Other current liabilities	95	51
Total Current Liabilities	1,483	361
Debt, long-term portion	6,370	1,277
Intercompany Payable		3,042
Other long-term liabilities	147	158
Total Liabilities	11,042	4,838
Long-term Debt, Noncurrent, Intercompany Transactions	3,042
Dynegy Stockholders’ Equity	2,921	3,023
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	2,921	3,023
Noncontrolling interest	0	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable	2,921	3,023
Total Liabilities and Equity	13,963	7,861
Escrow Issuers
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents		0	0
Restricted cash		113
Accounts receivable, net		0
Inventory		0
Other current assets		6
Total Current Assets		119
Property, Plant and Equipment, Net		0
Investment in affiliates		0
Restricted cash		5,100
Other long-term assets		47
Intercompany Receivables		0
Total Assets		5,266
Accounts payable		166
Other current liabilities		67
Total Current Liabilities		233
Debt, long-term portion		5,100
Intercompany Payable		0
Other long-term liabilities		0
Total Liabilities		5,333
Dynegy Stockholders’ Equity		(67)
Intercompany note receivable		0
Total Dynegy Stockholders’ Equity		(67)
Noncontrolling interest		0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable		(67)
Total Liabilities and Equity		5,266
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	94	54	154	42
Restricted cash	0	0
Accounts receivable, net	1,503	672
Inventory	331	88
Other current assets	335	125
Total Current Assets	2,263	939
Property, Plant and Equipment, Net	7,813	2,812
Investment in affiliates	190	0
Restricted cash		0
Other long-term assets	133	53
Goodwill	797
Intercompany Receivables	0	0
Total Assets	11,196	3,804
Accounts payable	238	112
Other current liabilities	277	250
Total Current Liabilities	515	362
Debt, long-term portion	122	0
Intercompany Payable	0	0
Other long-term liabilities	317	105
Total Liabilities	954	467
Dynegy Stockholders’ Equity	13,284	6,379
Intercompany note receivable	(3,042)	(3,042)
Total Dynegy Stockholders’ Equity	10,242	3,337
Noncontrolling interest	0	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable	10,242	3,337
Total Liabilities and Equity	11,196	3,804
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	84	174	$ 215	$ 0
Restricted cash	39	0
Accounts receivable, net	130	176
Inventory	266	120
Other current assets	55	73
Total Current Assets	574	543
Property, Plant and Equipment, Net	534	443
Investment in affiliates	0	0
Restricted cash		0
Other long-term assets	50	57
Goodwill	0
Intercompany Receivables	0	0
Total Assets	1,158	1,043
Accounts payable	396	220
Other current liabilities	162	97
Total Current Liabilities	558	317
Debt, long-term portion	714	698
Intercompany Payable	17	17
Other long-term liabilities	138	190
Total Liabilities	1,427	1,222
Dynegy Stockholders’ Equity	(267)	(179)
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	(267)	(179)
Noncontrolling interest	(2)	0
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest, Excluding Intercompany Receivable	(269)	(179)
Total Liabilities and Equity	1,158	1,043
Consolidated Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Other long-term assets	$ 260	$ 203

Condensed Consolidating Fina116

Condensed Consolidating Financial Information - Statement of Operations (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues	$ 1,016		$ 1,232		$ 990		$ 632		$ 599	$ 615	$ 521	$ 762	$ 3,870	$ 2,497	$ 1,466
Cost of sales, excluding depreciation expense													(2,028)	(1,661)	(1,145)
Gross margin													1,842	836	321
Operating and maintenance expense													(839)	(477)	(308)
Depreciation expense													(587)	(247)	(216)
Impairments	(25)		(74)										(99)	0	0
Gain (loss) on sale of assets, net													(1)	18	2
General and administrative expense													(128)	(114)	(97)
Acquisition and integration costs													(124)	(35)	(20)
Operating income (loss)	(13)	[1]	107	[1]	10	[1]	(40)	[1]	12	22	(54)	1	64	(19)	(318)
Bankruptcy reorganization items, net													0	3	(1)
Earnings from unconsolidated investments													1	10	2
Equity in losses from investments in affiliates													0	0	0
Interest expense													(546)	(223)	(97)
Loss on extinguishment of debt													0	0	(11)
Other income and expense, net													54	(39)	8
Loss before income taxes													(427)	(268)	(417)
Income tax benefit (Note 14)													474	1	58
Income (loss) from continuing operations before income taxes														(268)
Income (loss) from continuing operations													47	(267)	(359)
Income from discontinued operations, net of tax (Note 21)													0	0	3
Net loss	(134)		(24)		386		(181)		(103)	(5)	(122)	(37)	47	(267)	(356)
Less: Net income attributable to noncontrolling interest													(3)	6	0
Net loss attributable to Dynegy Inc.	$ (140)		$ (29)		$ 382		$ (185)		$ (109)	$ (5)	$ (123)	$ (41)	50	(273)	(356)
Eliminations
Revenues													(4)	0	0
Cost of sales, excluding depreciation expense													4	0	0
Gross margin													0	0	0
Operating and maintenance expense													0	0	0
Depreciation expense													0	0	0
Impairments													0
Gain (loss) on sale of assets, net													0	0	0
General and administrative expense													0	0	0
Acquisition and integration costs													0	0	0
Operating income (loss)													0	0	0
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													0	0	0
Equity in losses from investments in affiliates													(476)	131	315
Interest expense													0	1	0
Loss on extinguishment of debt															0
Other income and expense, net													0	(1)	0
Loss before income taxes													(476)	131	315
Income tax benefit (Note 14)													0	0	0
Income (loss) from continuing operations before income taxes															315
Income from discontinued operations, net of tax (Note 21)															2
Net loss													(476)	131	317
Less: Net income attributable to noncontrolling interest													0	0	0
Net loss attributable to Dynegy Inc.													(476)	131	317
Parent
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
Gain (loss) on sale of assets, net													0	0	0
General and administrative expense													(6)	(9)	(5)
Acquisition and integration costs													0	0	0
Operating income (loss)													(6)	(9)	(5)
Bankruptcy reorganization items, net														3	0
Earnings from unconsolidated investments													0	0	0
Equity in losses from investments in affiliates													476	(131)	(315)
Interest expense													(475)	(89)	(56)
Loss on extinguishment of debt															(8)
Other income and expense, net													55	(39)	4
Loss before income taxes													50	(265)	(380)
Income tax benefit (Note 14)													0	(8)	21
Income (loss) from continuing operations before income taxes															(359)
Income from discontinued operations, net of tax (Note 21)															3
Net loss													50	(273)	(356)
Less: Net income attributable to noncontrolling interest													0	0	0
Net loss attributable to Dynegy Inc.													50	(273)	(356)
Escrow Issuers
Revenues														0
Cost of sales, excluding depreciation expense														0
Gross margin														0
Operating and maintenance expense														0
Depreciation expense														0
Gain (loss) on sale of assets, net														0
General and administrative expense														0
Acquisition and integration costs														0
Operating income (loss)														0
Bankruptcy reorganization items, net														0
Earnings from unconsolidated investments														0
Equity in losses from investments in affiliates														0
Interest expense														(67)
Other income and expense, net														0
Loss before income taxes														(67)
Income tax benefit (Note 14)														0
Net loss														(67)
Less: Net income attributable to noncontrolling interest														0
Net loss attributable to Dynegy Inc.														(67)
Guarantor Subsidiaries
Revenues													2,979	1,651	1,398
Cost of sales, excluding depreciation expense													(1,485)	(1,065)	(1,099)
Gross margin													1,494	586	299
Operating and maintenance expense													(570)	(279)	(293)
Depreciation expense													(500)	(210)	(213)
Impairments													(74)
Gain (loss) on sale of assets, net													(1)	18	2
General and administrative expense													(91)	(60)	(90)
Acquisition and integration costs													(124)	0	0
Operating income (loss)													134	55	(295)
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													1	10	2
Equity in losses from investments in affiliates													0	0	0
Interest expense													(1)	0	(36)
Loss on extinguishment of debt															(3)
Other income and expense, net													(1)	1	3
Loss before income taxes													133	66	(329)
Income tax benefit (Note 14)													471	0	58
Income (loss) from continuing operations before income taxes															(271)
Income from discontinued operations, net of tax (Note 21)															(2)
Net loss													604	66	(273)
Less: Net income attributable to noncontrolling interest													0	0	0
Net loss attributable to Dynegy Inc.													604	66	(273)
Non-Guarantor Subsidiaries
Revenues													895	846	68
Cost of sales, excluding depreciation expense													(547)	(596)	(46)
Gross margin													348	250	22
Operating and maintenance expense													(269)	(198)	(15)
Depreciation expense													(87)	(37)	(3)
Impairments													(25)
Gain (loss) on sale of assets, net													0	0	0
General and administrative expense													(31)	(45)	(2)
Acquisition and integration costs													0	(35)	(20)
Operating income (loss)													(64)	(65)	(18)
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													0	0	0
Equity in losses from investments in affiliates													0	0	0
Interest expense													(70)	(68)	(5)
Loss on extinguishment of debt															0
Other income and expense, net													0	0	0
Loss before income taxes													(134)	(133)	(23)
Income tax benefit (Note 14)													3	9	(21)
Income (loss) from continuing operations before income taxes															(44)
Income from discontinued operations, net of tax (Note 21)															0
Net loss													(131)	(124)	(44)
Less: Net income attributable to noncontrolling interest													(3)	6	0
Net loss attributable to Dynegy Inc.													$ (128)	$ (130)	(44)
Consolidated Entities [Member]
Bankruptcy reorganization items, net															0
Other income and expense, net															$ 7
[1]	The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million, respectively. See Note 9—Property, Plant and Equipment for more information.

Condensed Consolidating Fina117

Condensed Consolidating Financial Information - Comprehensive Income (Loss) (Details) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net income (loss)		$ (134)	$ (24)	$ 386	$ (181)	$ (103)	$ (5)	$ (122)	$ (37)	$ 47	$ (267)	$ (356)
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31										4	(36)	57
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)	[1]									0	0	(7)
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense	[2]									4	5	2
Other comprehensive income from investment in affiliates										0	0	0
Other comprehensive income (loss), net of tax										0	(41)	48
Comprehensive income (loss)										47	(308)	(308)
Less: Comprehensive income (loss) attributable to noncontrolling interest										(2)	3	1
Total comprehensive income (loss) attributable to Dynegy Inc.										49	(311)	(309)
Amortization of unrecognized prior service credit and actuarial gain, tax	[2]									0	0	0
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										(476)	131	317
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31										0	0	0
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)											0	0
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense										0	0	0
Other comprehensive income from investment in affiliates										(11)	16	(4)
Other comprehensive income (loss), net of tax										(11)	16	(4)
Comprehensive income (loss)										(487)	147	313
Less: Comprehensive income (loss) attributable to noncontrolling interest										(1)	(3)	(1)
Total comprehensive income (loss) attributable to Dynegy Inc.										(486)	150	314
Parent
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										50	(273)	(356)
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31										(8)	(20)	53
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)											0	(7)
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense										3	5	2
Other comprehensive income from investment in affiliates										11	(16)	4
Other comprehensive income (loss), net of tax										0	(41)	48
Comprehensive income (loss)										50	(314)	(308)
Less: Comprehensive income (loss) attributable to noncontrolling interest										1	3	1
Total comprehensive income (loss) attributable to Dynegy Inc.										49	(317)	(309)
Net gain and plan amendments, tax										0	0	31
Amortization of unrecognized prior service credit and actuarial gain, tax										0	0	0
Escrow Issuers
Condensed Financial Statements, Captions [Line Items]
Net income (loss)											(67)
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31											0
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)											0
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense											0
Other comprehensive income from investment in affiliates											0
Other comprehensive income (loss), net of tax											0
Comprehensive income (loss)											(67)
Less: Comprehensive income (loss) attributable to noncontrolling interest											0
Total comprehensive income (loss) attributable to Dynegy Inc.											(67)
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										604	66	(273)
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31										2	0	0
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)											0	0
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense										0	0	0
Other comprehensive income from investment in affiliates										0	0	0
Other comprehensive income (loss), net of tax										2	0	0
Comprehensive income (loss)										606	66	(273)
Less: Comprehensive income (loss) attributable to noncontrolling interest										0	0	0
Total comprehensive income (loss) attributable to Dynegy Inc.										606	66	(273)
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)										(131)	(124)	(44)
Actuarial gain (loss) and plan amendments, net of tax of zero, zero and $31										10	(16)	4
Reclassification of curtailment gain included in net loss (net of tax of zero, zero, and zero, respectively)											0	0
Amortization of unrecognized prior service credit and actuarial gain, net of zero tax expense										1	0	0
Other comprehensive income from investment in affiliates										0	0	0
Other comprehensive income (loss), net of tax										9	(16)	4
Comprehensive income (loss)										(122)	(140)	(40)
Less: Comprehensive income (loss) attributable to noncontrolling interest										(2)	3	1
Total comprehensive income (loss) attributable to Dynegy Inc.										$ (120)	$ (143)	$ (41)
[1]	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—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 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Condensed Consolidating Fina118

Condensed Consolidating Financial Information - Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	$ 94	$ 163	$ 175
Capital expenditures	275	132	98
Proceeds from asset sales, net	0	18	3
(Increase) decrease in restricted cash	5,148	(5,148)	335
Acquisitions, net of cash acquired/divestitures	6,078	0	(234)
Net intercompany transfers	0	0	0
Distributions from unconsolidated affiliates	8	0	0
Other investing	3	0	0
Net cash provided by (used in) investing activities	(1,194)	(5,262)	474
Proceeds from issuance of preferred stock	0	400	0
Proceeds from issuance of common stock	0	744	0
Proceeds from long-term borrowings	97	5,112	1,768
Repayments of borrowings, including debt extinguishment costs	(31)	(14)	(1,917)
Financing costs from debt issuance	(31)	(57)	0
Financing costs from equity issuances	(6)	(38)	0
Dividends paid	(23)	0	0
Net intercompany transfers	0	0	0
Interest rate swap settlement payments	(17)	(18)	(5)
Repurchase of common stock	(250)	0	0
Other financing	(4)	(3)	0
Net cash provided by (used in) financing activities	(265)	6,126	(154)
Net increase (decrease) in cash and cash equivalents	(1,365)	1,027	495
Cash and cash equivalents, beginning of period	1,870	843	348
Cash and cash equivalents, end of period	505	1,870	843
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	0	0	0
Capital expenditures	0	0	0
Proceeds from asset sales, net		0	0
(Increase) decrease in restricted cash	0	0	0
Acquisitions, net of cash acquired/divestitures	0		0
Net intercompany transfers	(448)	(162)	1,044
Distributions from unconsolidated affiliates	0
Other investing	0
Net cash provided by (used in) investing activities	(448)	(162)	1,044
Proceeds from issuance of preferred stock		0
Proceeds from issuance of common stock		0
Proceeds from long-term borrowings	0	0	0
Repayments of borrowings, including debt extinguishment costs	0	0	0
Financing costs from debt issuance	0	0
Financing costs from equity issuances	0	0
Dividends paid	0
Net intercompany transfers	448	162	(1,044)
Interest rate swap settlement payments	0	0	0
Repurchase of common stock	0
Other financing	0	0
Net cash provided by (used in) financing activities	448	162	(1,044)
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(352)	(70)	(61)
Capital expenditures	13	0	0
Proceeds from asset sales, net		0	0
(Increase) decrease in restricted cash	5,148	0	29
Acquisitions, net of cash acquired/divestitures	6,207		0
Net intercompany transfers	448	162	(1,044)
Distributions from unconsolidated affiliates	0
Other investing	0
Net cash provided by (used in) investing activities	(624)	162	(1,015)
Proceeds from issuance of preferred stock		400
Proceeds from issuance of common stock		744
Proceeds from long-term borrowings	0	0	1,753
Repayments of borrowings, including debt extinguishment costs	(8)	(8)	(504)
Financing costs from debt issuance	(31)	(1)
Financing costs from equity issuances	(6)	(38)
Dividends paid	(23)
Net intercompany transfers	0	0	0
Interest rate swap settlement payments	(17)	(18)	(5)
Repurchase of common stock	(250)
Other financing	(4)	(3)
Net cash provided by (used in) financing activities	(339)	1,076	1,244
Net increase (decrease) in cash and cash equivalents	(1,315)	1,168	168
Cash and cash equivalents, beginning of period	1,642	474	306
Cash and cash equivalents, end of period	327	1,642	474
Escrow Issuers
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities		(62)
Capital expenditures		0
Proceeds from asset sales, net		0
(Increase) decrease in restricted cash		(5,148)
Net intercompany transfers		0
Net cash provided by (used in) investing activities		(5,148)
Proceeds from issuance of preferred stock		0
Proceeds from issuance of common stock		0
Proceeds from long-term borrowings		5,100
Repayments of borrowings, including debt extinguishment costs		0
Financing costs from debt issuance		(56)
Financing costs from equity issuances		0
Net intercompany transfers		166
Interest rate swap settlement payments		0
Other financing		0
Net cash provided by (used in) financing activities		5,210
Net increase (decrease) in cash and cash equivalents		0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period		0	0
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	574	353	254
Capital expenditures	199	87	97
Proceeds from asset sales, net		18	3
(Increase) decrease in restricted cash	0	0	306
Acquisitions, net of cash acquired/divestitures	(29)		0
Net intercompany transfers	0	0	0
Distributions from unconsolidated affiliates	8
Other investing	3
Net cash provided by (used in) investing activities	(159)	(69)	212
Proceeds from issuance of preferred stock		0
Proceeds from issuance of common stock		0
Proceeds from long-term borrowings	78	12	15
Repayments of borrowings, including debt extinguishment costs	(23)	(6)	(1,413)
Financing costs from debt issuance	0	0
Financing costs from equity issuances	0	0
Dividends paid	0
Net intercompany transfers	(430)	(390)	1,044
Interest rate swap settlement payments	0	0	0
Repurchase of common stock	0
Other financing	0	0
Net cash provided by (used in) financing activities	(375)	(384)	(354)
Net increase (decrease) in cash and cash equivalents	40	(100)	112
Cash and cash equivalents, beginning of period	54	154	42
Cash and cash equivalents, end of period	94	54	154
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by (used in) operating activities	(128)	(58)	(18)
Capital expenditures	63	45	1
Proceeds from asset sales, net		0	0
(Increase) decrease in restricted cash	0	0	0
Acquisitions, net of cash acquired/divestitures	(100)		(234)
Net intercompany transfers	0	0	0
Distributions from unconsolidated affiliates	0
Other investing	0
Net cash provided by (used in) investing activities	37	(45)	233
Proceeds from issuance of preferred stock		0
Proceeds from issuance of common stock		0
Proceeds from long-term borrowings	19	0	0
Repayments of borrowings, including debt extinguishment costs	0	0	0
Financing costs from debt issuance	0	0
Financing costs from equity issuances	0	0
Dividends paid	0
Net intercompany transfers	(18)	62	0
Interest rate swap settlement payments	0	0	0
Repurchase of common stock	0
Other financing	0	0
Net cash provided by (used in) financing activities	1	62	0
Net increase (decrease) in cash and cash equivalents	(90)	(41)	215
Cash and cash equivalents, beginning of period	174	215	0
Cash and cash equivalents, end of period	$ 84	$ 174	$ 215

Discontinued Operations (Detail

Discontinued Operations (Details) $ in Millions	Nov. 04, 2013USD ($)
DNE Debtor Entities
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from facilities sale transactions	$ 1

Restructuring Charges - Narrati

Restructuring Charges - Narrative (Details) - Employee Severance $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Position	Dec. 31, 2014USD ($)Position	Dec. 31, 2013USD ($)Position
AER Acquisition
Restructuring Cost and Reserve [Line Items]
Positions eliminated | Position		106	102
Payments for restructuring		$ 12	$ 3
EquiPower Acquisition
Restructuring Cost and Reserve [Line Items]
Positions eliminated | Position	49
Payments for restructuring	$ 14
Reimbursement received	$ 3

Restructuring Charges - Severan

Restructuring Charges - Severance Related Costs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Employee Severance and Retention Benefits
Restructuring Reserve [Roll Forward]
Beginning of period		$ 0	$ 12	$ 2
Expense	[1]	16	3	14
Payments		(15)	(15)	(4)
End of period		1	0	12
Retention
Restructuring Reserve [Roll Forward]
Expense		$ 1	$ 1	$ 3
[1]	Expense during the years ended December 31, 2015, 2014 and 2013 includes $1 million, $1 million and $3 million in retention benefits, respectively.

Segment Information - Narrative

Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2015segment
Segment Reporting [Abstract]
Reportable segments	3

Segment Information - Reportabl

Segment Information - Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended												12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Information
Unaffiliated revenues													$ 3,870	$ 2,497	$ 1,466
Intercompany revenues													0	0	0
Total revenues	$ 1,016		$ 1,232		$ 990		$ 632		$ 599	$ 615	$ 521	$ 762	3,870	2,497	1,466
Depreciation expense													(587)	(247)	(216)
Impairments	(25)		(74)										(99)	0	0
Gain (loss) on sale of assets, net													(1)	18	2
General and administrative expense													(128)	(114)	(97)
Operating income (loss)	(13)	[1]	107	[1]	10	[1]	(40)	[1]	12	22	(54)	1	64	(19)	(318)
Bankruptcy reorganization items, net													0	3	(1)
Earnings from unconsolidated investments													1	10	2
Interest expense													(546)	(223)	(97)
Loss on extinguishment of debt													0	0	(11)
Other items, net													54	(39)	8
Loss before income taxes													(427)	(268)	(417)
Income tax benefit													474	1	58
Loss from continuing operations													47	(267)	(359)
Income from discontinued operations, net of tax (Note 21)													0	0	3
Net income (loss)	(134)		(24)		386		(181)		(103)	(5)	(122)	(37)	47	(267)	(356)
Less: Net income (loss) attributable to noncontrolling interest													(3)	6	0
Net loss attributable to Dynegy Inc.	(140)		$ (29)		$ 382		$ (185)		(109)	$ (5)	$ (123)	$ (41)	50	(273)	(356)
Identifiable assets (domestic)	11,539								11,232				11,539	11,232	5,291
Investment in unconsolidated affiliate	190												190
Capital expenditures													(275)	(132)	(98)
Intersegment Eliminations
Segment Information
Unaffiliated revenues													0	0	0
Intercompany revenues													0	0	0
Total revenues													0	0	0
Depreciation expense													(4)	(4)	(3)
Impairments													0
Gain (loss) on sale of assets, net													0	0	0
General and administrative expense													(128)	(114)	(97)
Operating income (loss)													(252)	(136)	(101)
Bankruptcy reorganization items, net														3	(1)
Earnings from unconsolidated investments													0	0	0
Interest expense													(546)	(223)	97
Loss on extinguishment of debt															(8)
Other items, net													55	(39)	6
Income tax benefit													474	1	58
Income from discontinued operations, net of tax (Note 21)															3
Identifiable assets (domestic)	507								6,998				507	6,998	645
Investment in unconsolidated affiliate	0												0
Capital expenditures													(13)	(4)	(2)
Coal | Operating Segments
Segment Information
Unaffiliated revenues													1,298	587	469
Intercompany revenues													(134)	6	(2)
Total revenues													1,164	593	467
Depreciation expense													(138)	(51)	(50)
Impairments													(99)
Gain (loss) on sale of assets, net													0	0	2
General and administrative expense													0	0	0
Operating income (loss)													(93)	40	(207)
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													0	0	0
Loss on extinguishment of debt															(5)
Other items, net													(1)	0	0
Identifiable assets (domestic)	2,324								1,168				2,324	1,168	1,153
Investment in unconsolidated affiliate	0												0
Capital expenditures													(87)	(39)	(42)
IPH | Operating Segments
Segment Information
Unaffiliated revenues													804	850	67
Intercompany revenues													(5)	(4)	0
Total revenues													799	846	67
Depreciation expense													(29)	(37)	(3)
Impairments													0
Gain (loss) on sale of assets, net													0	0	0
General and administrative expense													0	0	0
Operating income (loss)													49	(2)	(17)
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													0	0	0
Loss on extinguishment of debt															0
Other items, net													0	0	0
Identifiable assets (domestic)	897								1,039				897	1,039	1,190
Investment in unconsolidated affiliate	0												0
Capital expenditures													(63)	(45)	(1)
Gas | Operating Segments
Segment Information
Unaffiliated revenues													1,768	1,060	930
Intercompany revenues													139	(2)	2
Total revenues													1,907	1,058	932
Depreciation expense													(416)	(155)	(160)
Impairments													0
Gain (loss) on sale of assets, net													(1)	18	0
General and administrative expense													0	0	0
Operating income (loss)													360	79	7
Bankruptcy reorganization items, net														0	0
Earnings from unconsolidated investments													1	10	2
Loss on extinguishment of debt															2
Other items, net													0	0	2
Identifiable assets (domestic)	7,811								$ 2,027				7,811	2,027	2,303
Investment in unconsolidated affiliate	$ 190												190
Capital expenditures													$ (112)	$ (44)	$ (53)
[1]	The results for the quarters ended September 30, 2015 and December 31, 2015, include impairment charges of $74 million and $25 million, respectively. See Note 9—Property, Plant and Equipment for more information.

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, 2015	Dec. 31, 2014	Dec. 31, 2013
PJM | Coal, IPH and Gas
Revenue, Major Customer [Line Items]
Revenues	$ 1,088
PJM | Gas
Revenue, Major Customer [Line Items]
Revenues			$ 275
MISO | Coal and IPH
Revenue, Major Customer [Line Items]
Revenues	$ 842	$ 836	526
NYISO | Gas
Revenue, Major Customer [Line Items]
Revenues		$ 342	231
CAISO | Gas
Revenue, Major Customer [Line Items]
Revenues			$ 221

Subsequent Event (Details)

Subsequent Event (Details) - Subsequent Event $ in Millions	Feb. 25, 2016USD ($)MW
GDF Suez Energy North America
Subsequent Event [Line Items]
Base purchase price | $	$ 3,300
Power acquired	8,700
GDF Suez Energy North America | Dynegy, Inc
Subsequent Event [Line Items]
Percent of voting interests acquired (as a percentage)	65.00%
GDF Suez Energy North America | ECP
Subsequent Event [Line Items]
Percent of voting interests acquired (as a percentage)	35.00%
GDF Suez Energy North America | Natural Gas
Subsequent Event [Line Items]
Power acquired	8,000
GDF Suez Energy North America | Coal
Subsequent Event [Line Items]
Power acquired	700
ECP | Dynegy, Inc
Subsequent Event [Line Items]
Stock issued, value | $	$ 150