Dyne Therapeutics 10-Q 2 Nov 16 2016 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2016	Oct. 12, 2016
Document and Entity Information [Abstract]
Entity Registrant Name	DYNEGY INC.
Entity Central Index Key	1,379,895
Document Type	10-Q
Document Period End Date	Sep. 30, 2016
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		117,293,478
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q3

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 1,458	$ 505
Restricted cash	85	39
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	374	402
Inventory	447	597
Assets from risk management activities	73	100
Intangible assets	54	102
Prepayments and other current assets	148	187
Total Current Assets	2,639	1,932
Property, Plant and Equipment, Net	7,252	8,347
Investment in unconsolidated affiliate	173	190
Restricted cash	2,000	0
Assets from risk management activities	40	18
Goodwill	799	797
Intangible assets	28	62
Other long-term assets	93	113
Total Assets	13,024	11,459
Current Liabilities
Accounts payable	263	292
Accrued interest	191	74
Intangible liabilities	33	85
Accrued liabilities and other current liabilities	120	125
Liabilities from risk management activities	92	103
Asset retirement obligations	45	50
Debt, current portion, net	167	80
Total Current Liabilities	911	809
Debt, long-term portion, net	9,356	7,129
Liabilities from risk management activities	69	105
Asset retirement obligations	238	230
Deferred income taxes	36	29
Intangible liabilities	39	55
Other long-term liabilities	168	183
Total Liabilities	10,817	8,540
Commitments and Contingencies (Note 14)
Stockholders’ Equity
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,619,600 shares issued and 117,293,478 shares outstanding at September 30, 2016; 128,228,477 shares issued and 116,902,355 outstanding at December 31, 2015	1	1
Additional paid-in capital	3,541	3,187
Accumulated other comprehensive income, net of tax	15	19
Accumulated deficit	(1,746)	(686)
Total Dynegy Stockholders’ Equity	2,211	2,921
Noncontrolling interest	(4)	(2)
Total Equity	2,207	2,919
Total Liabilities and Equity	13,024	11,459
Series A 5.375% mandatory convertible preferred stock
Stockholders’ Equity
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding, respectively	$ 400	$ 400

CONSOLIDATED BALANCE SHEETS (PA

CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2015
Allowance for doubtful accounts	$ 1	$ 1
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	128,619,600	128,228,477
Common stock, shares outstanding	117,293,478	116,902,355
Series A 5.375% mandatory convertible preferred stock
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 issues	4,000,000	4,000,000
Preferred stock, shares outstanding	4,000,000	4,000,000

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Statement [Abstract]
Revenues		$ 1,184	$ 1,232	$ 3,211	$ 2,854
Cost of sales, excluding depreciation expense		(660)	(621)	(1,698)	(1,494)
Gross margin		524	611	1,513	1,360
Operating and maintenance expense		(218)	(219)	(695)	(580)
Depreciation expense		(163)	(174)	(494)	(413)
Impairments		(212)	(74)	(857)	(74)
General and administrative expense		(41)	(29)	(117)	(94)
Acquisition and integration costs		(7)	(8)	(8)	(121)
Other		0	0	(16)	(1)
Operating income (loss)		(117)	107	(674)	77
Earnings (losses) from unconsolidated investment		4	(4)	7	(1)
Interest expense		(166)	(145)	(449)	(413)
Other income and expense, net		29	46	60	45
Income (loss) before income taxes		(250)	4	(1,056)	(292)
Income tax benefit (expense) (Note 15)		1	(28)	(6)	473
Net income (loss)		(249)	(24)	(1,062)	181
Less: Net loss attributable to noncontrolling interest		0	0	(2)	(3)
Net income (loss) attributable to Dynegy Inc.		(249)	(24)	(1,060)	184
Less: Dividends on preferred stock		5	5	16	16
Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic earnings (loss) per share		$ (254)	$ (29)	$ (1,076)	$ 168
Earnings (Loss) Per Share (Note 18):
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	[1]	$ (1.81)	$ (0.23)	$ (8.54)	$ 1.33
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	[2]	$ (1.81)	$ (0.23)	$ (8.54)	$ 1.31
Basic shares outstanding (shares)	[1]	140	126	126	126
Diluted shares outstanding (shares)		140	126	126	140
[1]	For the three and nine months ended September 30, 2016, the TEUs are assumed to be outstanding at the minimum settlement amount, or 23,092,460 shares, for weighted-average shares for basic earnings (loss) per share. Please read Note 12—Tangible Equity Units for further discussion.
[2]	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015.

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (249)	$ (24)	$ (1,062)	$ 181
Other comprehensive income (loss) before reclassifications:
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)	0	13	0	8
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	(2)	(1)	(4)	(3)
Other comprehensive income (loss), net of tax	(2)	12	(4)	5
Comprehensive income (loss)	(251)	(12)	(1,066)	186
Comprehensive income (loss) attributable to noncontrolling interest	0	1	(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.	$ (251)	$ (13)	$ (1,064)	$ 188

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (PARENTHETICAL) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Statement of Comprehensive Income [Abstract]
Tax on actuarial loss	$ 0	$ 2	$ 0	$ 2
Tax on amortization of unrecognized prior service cost (credit) and actuarial loss (gain)	$ 0	$ 0	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$ (1,062)	$ 181
Adjustments to reconcile net income (loss) to net cash flows from operating activities:
Depreciation expense	494	413
Non-cash interest expense	37	25
Amortization of intangibles	17	(18)
Risk management activities	(75)	(117)
(Earnings) losses from unconsolidated investment	(7)	1
Deferred income taxes	6	(473)
Impairments	857	74
Change in value of common stock warrants	(5)	(43)
Other	1	38
Changes in working capital:
Accounts receivable, net	32	(48)
Inventory	153	(52)
Prepayments and other current assets	179	95
Accounts payable and accrued liabilities	104	227
Distributions from unconsolidated investment	1	3
Changes in restricted cash	(1)	0
Changes in non-current assets	(94)	(23)
Changes in non-current liabilities	12	19
Net cash provided by operating activities	649	302
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(259)	(171)
Acquisitions, net of cash acquired	0	(6,078)
Decrease (increase) in restricted cash	(2,045)	5,148
Distributions from unconsolidated affiliate	14	8
Other investing	10	(6)
Net cash used in investing activities	(2,280)	(1,099)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	2,277	57
Repayments of borrowings	(21)	(29)
Proceeds from issuance of equity, net of issuance costs	(359)	6
Preferred stock dividends paid	(16)	(17)
Interest rate swap settlement payments	(13)	(13)
Repurchase of common stock	0	(127)
Other financing	(2)	(4)
Net cash provided by (used in) financing activities	2,584	(139)
Net increase (decrease) in cash and cash equivalents	953	(936)
Cash and cash equivalents, beginning of period	505	1,870
Cash and cash equivalents, end of period	1,458	934
Other non-cash investing and financing activity:
Change in capital expenditures included in accounts payable	(10)	(6)
Non-cash consideration transferred for Acquisitions	0	(105)
Change in capital expenditures pursuant to an equipment financing agreement	$ 11	$ 63

Basis of Presentation and Organ

Basis of Presentation and Organization	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation and Organization	Note 1—Basis of Presentation and Organization The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by the Generally Accepted Accounting Principles of the United States of America (“GAAP”). The unaudited consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Certain prior period amounts in our unaudited consolidated financial statements have been reclassified to conform to current year presentation. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2015 , filed with the SEC on February 25, 2016, which we refer to as our “Form 10-K.” Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. Our current business operations are focused primarily on the unregulated power generation sector of the energy industry. We report the results of our power generation business as three segments in our unaudited consolidated financial statements: (i) the Coal segment (“Coal”), (ii) the IPH segment (“IPH”), and (iii) the Gas segment (“Gas”). Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 20—Segment Information for further discussion. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts, and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names, and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents. Genco’s $825 million Senior Notes are non-recourse to Dynegy.

Accounting Policies

Accounting Policies	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Accounting Policies	Note 2—Accounting Policies The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with GAAP. There have been no significant changes to our accounting policies during the nine months ended September 30, 2016 . Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors. Accounting Standards Adopted During the Current Period Hybrid Financial Instruments. In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-16-Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or Equity. The amendments in this ASU clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the amendments clarify that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the amendments clarify that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The amendments in this ASU also clarify that, in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (i.e., the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weight those terms and features. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for our debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We adopted these ASUs on January 1, 2016, on a retrospective basis affecting presentation on the unaudited consolidated balance sheets for all periods presented. Accordingly, we reclassified unamortized debt issuance costs of $3 million from Prepayments and other current assets to Debt, current portion, net and $77 million from Other long-term assets to Debt, long-term portion, net within our unaudited consolidated balance sheet as of December 31, 2015. 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, a nd (v) consolidation of certain investment funds. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements. Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements. Accounting Standards Not Yet Adopted Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Credit Losses. In June 2016, the FASB issued ASU 2016-13-Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this ASU require the measurement of all expected credit losses for financial assets, which include trade receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Debt Instruments. In March 2016, the FASB issued ASU 2016-06-Derivative and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments in this ASU clarify what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this ASU is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The amendments are effective for public business entities for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. All entities have the option of adopting the new requirements early, including adoption in an interim period. If an entity early adopts the new requirements in an interim period, it must reflect any adjustments as of the beginning of the fiscal year that includes that interim period. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements-Going Concern (Subtopic 205-40). The amendments in this ASU require management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued, when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years ending after December 15, 2016, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU, and subsequently issued amendments to the standard, develop a common revenue standard for GAAP and International Financial Reporting Standards 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 and its amendments is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Acquisitions	Note 3—Acquisitions Delta Transaction. On February 24, 2016, Atlas Power Finance, LLC (“Atlas” or the “Purchaser”), a wholly owned subsidiary of Atlas Power, LLC (“Atlas Power”), entered into a Stock Purchase Agreement, as amended and restated on June 27, 2016, (the “Delta Stock Purchase Agreement”) with GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), indirect subsidiaries of Engie S.A. Pursuant to the Delta Stock Purchase Agreement, the Purchaser will acquire approximately 9,058 MW of generation, including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “Delta Transaction”). On June 27, 2016, a wholly owned subsidiary of Dynegy acquired the 35 percent interest in Atlas Power (the “ECP Buyout”) held by certain affiliated investment funds of Energy Capital Partners III, LLC (the “ECP Funds”). As a result, Atlas Power became an indirect wholly owned subsidiary of Dynegy. In accordance with the agreement with Energy Capital Partners (“ECP”), Dynegy will pay ECP $375 million (the “ECP Buyout Price”) on the later of December 31, 2016, or three months after the closing of the Delta Transaction (the “First Payment Date”). Alternatively, Dynegy may pay the ECP Buyout Price after the First Payment Date, but in such case, the ECP Buyout Price would be subject to quarterly escalation up to a maximum of $468.5 million . Dynegy intends to pay the buyout price at or prior to the First Payment Date. The Purchaser and the Seller have agreed to indemnify the other for breaches of representations, warranties and covenants, and for certain other matters, subject to certain exceptions and limitations. The Delta Stock Purchase Agreement contains certain termination rights for both the Purchaser and the Seller, including if the closing does not occur within 12 months following the date of the Delta Stock Purchase Agreement. In the event the Delta Stock Purchase Agreement is terminated under certain circumstances, including the failure to obtain certain regulatory approvals, the Purchaser must pay GSENA the reverse termination fee of $132 million discussed below. Dynegy also entered into an amended and restated limited guarantee in favor of GSENA, pursuant to which Dynegy guarantees 100 percent of the Purchaser’s obligation to pay the reverse termination fee of $132 million if such fee becomes payable. Please read Note 14—Commitments and Contingencies —Indemnifications and Guarantees for further discussion. The Delta Stock Purchase Agreement includes customary representations, warranties and covenants by the parties. The Delta Transaction is subject to various closing conditions, including (i) expiration of the applicable waiting period, which was received on April 1, 2016, under the Hart-Scott-Rodino Act; (ii) obtaining required approvals from the FERC and the Public Utility Commission of Texas, the latter of which was received on July 20, 2016; (iii) no injunction or other orders preventing the consummation of the transactions contemplated under the Delta Stock Purchase Agreement; (iv) the completion of GSENA’s internal reorganization in all material respects in accordance with an exhibit attached to the Delta Stock Purchase Agreement; (v) the continuing accuracy of each party’s representations and warranties, and (vi) the satisfaction of other customary conditions. On June 8, 2016, we received a letter from FERC requesting additional information, to which we have responded. We expect the Delta Transaction to close in the fourth quarter of 2016 after satisfaction or waiver of these closing conditions. Delta Transaction Financing. On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the ECP Funds (the “PIPE Stock Purchase Agreement”), pursuant to which Dynegy will sell and issue to Terawatt at the closing of the Delta Transaction 13,711,152 shares of Dynegy common stock for $150 million (the “PIPE Transaction”). The closing of the PIPE Transaction is contingent on the closing of the Delta Transaction. In addition, Dynegy has agreed to enter into an Investor Rights Agreement, in the form attached to the PIPE Stock Purchase Agreement (the “Investor Rights Agreement”), with Terawatt at the closing of the PIPE Transaction. Under the Investor Rights Agreement, Terawatt will be entitled to certain rights, including certain registration rights, rights of first refusal with respect to issuances of our common stock and the designation of one individual to serve on our Board of Directors as long as Terawatt and its affiliates own at least 10 percent of our common stock. Further, the Investor Rights Agreement subjects Terawatt to certain obligations, including certain voting obligations and customary standstill and lock-up periods. On June 21, 2016, pursuant to a registered public offering, Dynegy issued 4.6 million tangible equity units (“TEUs”) for proceeds of $446 million , net of issuance costs of $14 million . Please read Note 12—Tangible Equity Units for further discussion. On June 27, 2016, Dynegy Finance IV, Inc. (“Finance IV”), a direct wholly-owned subsidiary of Dynegy, entered into a term loan credit agreement with certain lenders providing for a $2.0 billion , seven -year senior secured term loan facility (the “Tranche C Term Loan”), the net proceeds of which were placed into escrow pending the closing of the Delta Transaction. Under the escrow agreement, the applicable borrowings are subject to full liquidation and release to the lenders if the Delta Transaction is terminated or not consummated by February 24, 2017. Also, on June 27, 2016, Dynegy entered into a Third Amendment to the Credit Agreement (the “Third Amendment”), which, upon the release of funds from escrow, provides for (i) a $75 million revolving loan commitment increase to the incremental tranche B revolving loan commitments (the “Incremental Tranche B Revolver”), which has terms substantially the same as the terms of the existing incremental tranche B revolving loan commitments under the Credit Agreement, and (ii) conversion of the Tranche C Term Loan to an incremental $2.0 billion senior secured tranche C term loan. Please read Note 13—Debt —Credit Agreement and Finance IV Credit Agreement for further discussion. Dynegy intends to use the net proceeds associated with the PIPE Transaction, the TEUs, the Tranche C Term Loan, borrowings under its revolving credit facilities, and cash-on-hand to fund the Delta Transaction and pay related fees and expenses. EquiPower Acquisition. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of a stock purchase agreement dated August 21, 2014, as amended, our wholly-owned subsidiary, Dynegy Resource II, LLC purchased 100 percent of 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, our wholly-owned subsidiary Dynegy Resource III, LLC 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. Duke Midwest Acquisition. On April 2, 2015, pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended, our wholly-owned subsidiary Dynegy Resource I, LLC purchased 100 percent of the membership interests in Duke Energy Commercial Asset Management, LLC and Duke Energy Retail Sales, LLC, from two affiliates of Duke Energy Corporation (collectively, “Duke Energy”), thereby acquiring approximately 6,200 MW of generation in (i) three combined cycle natural gas-fired facilities located in Ohio and Pennsylvania, (ii) two natural gas-fired peaking facilities located in Ohio and Illinois, (iii) one oil-fired peaking facility located in Ohio, (iv) partial interests in five coal-fired facilities located in Ohio, and (v) a retail energy business for a base purchase price of approximately $2.8 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. Business Combination Accounting. The EquiPower Acquisition and the Duke Midwest Acquisition (collectively, the “Acquisitions”) have been accounted for in accordance with Accounting Standards Codification (“ASC”) 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition dates, April 1, 2015 and April 2, 2015, respectively. The valuation of these assets and liabilities is classified as Level 3 within the fair value hierarchy. To fair value working capital, we used available market information. Asset retirement obligations (“AROs”) were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations. To fair value the acquired property, plant and equipment (“PP&E”), we used a discounted cash flow (“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 and 2016. For the years 2017 through 2024, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors. For periods beyond 2024, we assumed a 2.5 percent growth rate. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for the years 2015 through 2019 and assumed a 2.5 percent growth rate, based upon management’s view of future conditions, thereafter. The resulting cash flows were then discounted using plant specific discount rates of approximately 8 percent to 10 percent for gas-fired generation facilities and approximately 9 percent to 13 percent for coal-fired generation facilities, based upon the asset’s age, efficiency, region, and years until retirement. Contracts with terms that were not at current market prices were also valued using a DCF analysis. The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability. The 3,460,053 shares of common stock of Dynegy, issued as part of the consideration for the EquiPower Acquisition, were valued at approximately $105 million based on the closing price of Dynegy’s common stock on the EquiPower Closing Date. As of June 30, 2016 , we completed our valuation of the assets acquired and liabilities assumed in connection with the Acquisitions. The following table summarizes the consideration paid and the fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 126 175 Inventory 167 105 272 Assets from risk management activities (including current portion of $4 million and $30 million, respectively) 4 33 37 Prepayments and other current assets 32 69 101 Property, plant and equipment 2,773 2,734 5,507 Investment in unconsolidated affiliate 200 — 200 Intangible assets (including current portion of $67 million and $36 million, respectively) 111 84 195 Other long-term assets 28 35 63 Total assets acquired 3,631 3,186 6,817 Accounts payable 27 96 123 Accrued liabilities and other current liabilities 21 10 31 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 509 — 509 Other long-term liabilities — 40 40 Total liabilities assumed 769 395 1,164 Identifiable net assets acquired 2,862 2,791 5,653 Goodwill 799 — 799 Net assets acquired $ 3,661 $ 2,791 $ 6,452 No acquisition costs related to the Acquisitions were incurred during the three and nine months ended September 30, 2016 . We incurred acquisition costs of $1 million and $86 million related to the Acquisitions for the three and nine months ended September 30, 2015 , respectively. These acquisition costs are included in Acquisition and integration costs in our unaudited consolidated statements of operations. Revenues of $543 million and $1,675 million and operating loss of $34 million and income of $146 million , attributable to the Acquisitions, are included in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 , respectively. Revenues of $626 million and $1,128 million and operating income of $120 million and $190 million , attributable to the Acquisitions, are included in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015 , respectively. Pro Forma Results. The unaudited pro forma financial results for the nine months ended September 30, 2015 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 as of January 1, 2014, nor are they indicative of future results of operations. (amounts in millions) Nine Months Ended September 30, 2015 Revenues $ 3,844 Net income $ 442 Net loss attributable to noncontrolling interests $ (3 ) Net income attributable to Dynegy Inc. $ 445

Unconsolidated Investments

Unconsolidated Investments	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Unconsolidated Investments	Note 4—Unconsolidated Investment Equity Method Investment 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 1,580 MW natural gas-fired facility located in Elwood, Illinois. At September 30, 2016 and December 31, 2015 , our equity method investment included in our unaudited consolidated balance sheets was $173 million and $190 million , respectively. Upon the acquisition of our Elwood investment, we recognized basis differences in the net assets of approximately $89 million related to working capital, PP&E, debt, and intangibles. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. Holders of the debt of our unconsolidated investment do not have recourse to us and our other subsidiaries. For the three and nine months ended September 30, 2016 , we recorded $4 million and $7 million in equity earnings related to our investment in Elwood, respectively. For the three and nine months ended September 30, 2015 , we recorded $4 million and $1 million in equity losses related to our investment in Elwood, respectively. These equity earnings (losses) are included in Earnings (losses) from unconsolidated investment in our unaudited consolidated statements of operations. For the nine months ended September 30, 2016 , we received a distribution of $15 million , of which $14 million was considered a return of investment. For the nine months ended September 30, 2015 , we received a distribution of $11 million , of which $8 million was considered a return of investment. At September 30, 2016 and December 31, 2015 , we have $10 million and $3 million in accounts receivable due from Elwood, respectively, which is included in Accounts receivable, net in our unaudited consolidated balance sheets. On March 28, 2016, Dynegy Marketing and Trade, LLC (“DMT”), a subsidiary of Dynegy, entered into (i) an Asset Management Agreement and (ii) a Fuel Supply and Fuel Management Services Agreement with Elwood Energy. Under these agreements, DMT provides gas supply and management services to meet Elwood Energy’s fuel supply requirements. For the three and nine months ended September 30, 2016 , we recorded $15 million and $27 million in revenues related to these agreements, respectively, which is reflected in Revenues in our unaudited consolidated statements of operations. On August 3, 2016, Dynegy announced that it has entered into an agreement to sell its 50 percent equity interest in the Elwood Energy facility in Elwood, IL, to J-Power USA Development Co. Ltd. for approximately $173 million (“the Elwood Sale”). Under the agreement, Elwood will not make distributions to its members prior to the closing of the Elwood Sale. As a result, we recorded an impairment charge of $9 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 , to write down our investment in Elwood to the sales price. Additionally, approximately $35 million of previously posted collateral will be returned to Dynegy at closing. Upon approval from the FERC, the sale is expected to close in the fourth quarter of 2016. 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 additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our unaudited consolidated statements of operations. The following tables present the ownership interests of the jointly owned facilities as of September 30, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. September 30, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 206 $ (33 ) $ 3 $ 176 Stuart (1) 39.0 % $ — $ — $ — $ — Conesville (1) 40.0 % $ 61 $ (2 ) $ 5 $ 64 Zimmer 46.5 % $ 116 $ (21 ) $ 4 $ 99 Killen (1) 33.0 % $ 18 $ (1 ) $ 2 $ 19 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. In the third quarter 2016, we impaired the book value of the jointly owned Stuart facility and recorded a charge of $55 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 . Please read Note 9—Property, Plant and Equipment for further discussion.

Risk Management Activities, Der

Risk Management Activities, Derivatives and Financial Instruments	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Risk Management Activities, Derivatives and Financial Instruments	Note 5—Risk Management Activities, Derivatives, and Financial Instruments The nature of our business necessarily involves commodity market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk. Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one - to three -year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term. Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our unaudited consolidated statements of operations. We have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases, and retail power sales which do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale,” in accordance with ASC 815, Derivatives and Hedging. As a result, the gains and losses with respect to these arrangements are not reflected in our unaudited consolidated financial statements until the delivery occurs. Quantitative Disclosures Related to Financial Instruments and Derivatives As of September 30, 2016 , we had net purchases and sales of derivative contracts outstanding in the following quantities: Contract Type Quantity Unit of Measure Fair Value (1) (dollars and quantities in millions) Purchases (Sales) Asset (Liability) Commodity contracts: Electricity derivatives (2) (58 ) MWh $ 25 Electricity basis derivatives (3) (30 ) MWh $ (8 ) Natural gas derivatives (2) 362 MMBtu $ (64 ) Natural gas basis derivatives 64 MMBtu $ (22 ) Coal derivatives (4) — Metric Ton $ (7 ) Emissions derivatives 5 Metric Ton $ (5 ) Interest rate swaps 771 U.S. Dollar $ (40 ) Common stock warrants (5) 16 Warrant $ (2 ) __________________________________________ (1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $73 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 tables present the fair value and balance sheet classification of derivatives in our unaudited consolidated balance sheets as of September 30, 2016 and December 31, 2015 . As of September 30, 2016 and December 31, 2015 , there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets. September 30, 2016 Gross amounts offset in the balance sheet Contract Type Location on Balance Sheet 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 $ 351 $ (238 ) $ — $ 113 Total derivative assets $ 351 $ (238 ) $ — $ 113 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (432 ) $ 238 $ 73 $ (121 ) Interest rate contracts Liabilities from risk management activities (40 ) — — (40 ) Common stock warrants Other long-term liabilities (2 ) — — (2 ) Total derivative liabilities $ (474 ) $ 238 $ 73 $ (163 ) Total derivatives $ (123 ) $ — $ 73 $ (50 ) December 31, 2015 Gross amounts offset in the balance sheet Contract Type Location on Balance Sheet Gross Fair Value Contract Netting Collateral or Margin Received or Paid Net Fair Value (amounts in millions) Derivative assets: Commodity contracts Assets from risk management activities $ 403 $ (285 ) $ — $ 118 Total derivative assets $ 403 $ (285 ) $ — $ 118 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (557 ) $ 285 $ 106 $ (166 ) Interest rate contracts Liabilities from risk management activities (42 ) — — (42 ) Common stock warrants Other long-term liabilities (7 ) — — (7 ) Total derivative liabilities $ (606 ) $ 285 $ 106 $ (215 ) Total derivatives $ (203 ) $ — $ 106 $ (97 ) Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to worsen, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. As of September 30, 2016 , the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features which are in a liability position and not fully collateralized is $26 million for which we have posted $12 million in collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program. The following table summarizes our cash collateral posted as of September 30, 2016 and December 31, 2015 , within Prepayments and other current assets in our unaudited consolidated balance sheets and the amount applied against short-term risk management activities: Location on Balance Sheet September 30, 2016 December 31, 2015 (amounts in millions) Gross collateral posted with counterparties $ 119 $ 162 Less: Collateral netted against risk management liabilities 73 106 Net collateral within Prepayments and other current assets $ 46 $ 56 Impact of Derivatives on the Unaudited Consolidated Statements of Operations The following discussion and table present the location and amount of gains and losses on derivative instruments in our unaudited consolidated statements of operations. Financial Instruments Not Designated as Hedges. We elect not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within our unaudited consolidated statements of operations. Our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015 include the impact of derivative financial instruments as presented below: Derivatives Not Designated as Hedges Location of Gain (Loss) Recognized in Income on Derivatives Three Months Ended September 30, Nine Months Ended 2016 2015 2016 2015 (amounts in millions) Commodity contracts Revenues $ (27 ) $ 48 $ 188 $ 120 Interest rate contracts Interest expense $ 1 $ (9 ) $ (11 ) $ (17 ) Common stock warrants Other income and (expense), net $ 4 $ 45 $ 5 $ 43

Fair Value Measurements

Fair Value Measurements	9 Months Ended
	Sep. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value Measurements	Note 6—Fair Value Measurements We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used the same valuation techniques for all periods presented. Please read Note 2 — Summary of Significant Accounting Policies — Fair Value Measurements in our Form 10-K for further discussion. The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2016 and December 31, 2015 , and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid: Fair Value as of September 30, 2016 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 248 $ 38 $ 286 Natural gas derivatives — 51 10 61 Emissions derivatives — 3 — 3 Coal derivatives — — 1 1 Total assets from commodity risk management activities $ — $ 302 $ 49 $ 351 Liabilities: . Liabilities from commodity risk management activities: Electricity derivatives $ — $ (221 ) $ (48 ) $ (269 ) Natural gas derivatives — (123 ) (24 ) (147 ) Emissions derivatives — (8 ) — (8 ) Coal derivatives — (8 ) — (8 ) Total liabilities from commodity risk management activities — (360 ) (72 ) (432 ) Liabilities from interest rate contracts — (40 ) — (40 ) Liabilities from outstanding common stock warrants (2 ) — — (2 ) Total liabilities $ (2 ) $ (400 ) $ (72 ) $ (474 ) Fair Value as of December 31, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 308 $ 40 $ 348 Natural gas derivatives — 40 2 42 Coal derivatives — 10 3 13 Total assets from commodity risk management activities $ — $ 358 $ 45 $ 403 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (267 ) $ (58 ) $ (325 ) Natural gas derivatives — (158 ) (34 ) (192 ) Diesel derivatives — (4 ) — (4 ) Coal derivatives — (35 ) (1 ) (36 ) Total liabilities from commodity risk management activities — (464 ) (93 ) (557 ) Liabilities from interest rate contracts — (42 ) — (42 ) Liabilities from outstanding common stock warrants (7 ) — — (7 ) Total liabilities $ (7 ) $ (506 ) $ (93 ) $ (606 ) Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts, and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. The forward market price of FTRs is derived using historical congestion patterns within the marketplace and heat rate derivative valuations are derived using a Black-Scholes spread model, which uses forward natural gas and power prices, market implied volatilities, and modeled correlation values. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps, and physical purchases executed in illiquid trading locations or on long dated contracts. The coal derivatives classified within Level 3 include financial swaps executed in illiquid trading locations. Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, natural gas and coal pricing, and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of September 30, 2016 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Input Significant Unobservable Input Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (10 ) Million MWh $ (7 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs (26 ) Million MWh $ (3 ) Historical congestion Forward price $0 - $6.00 Natural gas derivatives (1) 78 Million MMBtu $ (14 ) Illiquid location fixed price Forward price $1.05 - $1.35 Coal derivatives (1) — Thousand Tons $ 1 Illiquid location fixed price Forward price $6.10 - $7.45 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations. The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at June 30, 2016 $ (24 ) $ (15 ) $ 1 $ (38 ) Total gains (losses) included in earnings 9 (4 ) 1 6 Settlements (1) 5 5 (1 ) 9 Balance at September 30, 2016 $ (10 ) $ (14 ) $ 1 $ (23 ) Unrealized gains (losses) relating to instruments held as of September 30, 2016 $ 9 $ (4 ) $ 1 $ 6 Nine Months Ended September 30, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2015 $ (18 ) $ (32 ) $ 2 $ (48 ) Total gains included in earnings 4 — — 4 Settlements (1) 4 18 (1 ) 21 Balance at September 30, 2016 $ (10 ) $ (14 ) $ 1 $ (23 ) Unrealized gains relating to instruments held as of September 30, 2016 $ 4 $ — $ — $ 4 Three Months Ended September 30, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at June 30, 2015 $ (54 ) $ (11 ) $ (7 ) $ 4 $ (68 ) Total gains (losses) included in earnings 2 (3 ) — — (1 ) Settlements (1) 3 — 5 (1 ) 7 Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3 $ (62 ) Unrealized gains (losses) relating to instruments held as of September 30, 2015 $ 2 $ (3 ) $ — $ — $ (1 ) Nine Months Ended September 30, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Acquisitions (54 ) (14 ) (9 ) 5 (72 ) Total gains included in earnings 7 — — — 7 Settlements (1) 2 — 7 (2 ) 7 Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3 $ (62 ) Unrealized gains relating to instruments held as of September 30, 2015 $ 7 $ — $ — $ — $ 7 _________________________________________ (1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period. Gains and losses recognized for Level 3 recurring items are included in Revenues in our unaudited consolidated statements of operations for commodity derivatives. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any transfers between Level 1, Level 2, and Level 3 for the three and nine months ended September 30, 2016 and 2015 . Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy. During the nine months ended September 30, 2016 , as a result of impairment testing, we measured our Baldwin and Stuart facilities at fair value. See Note 9—Property, Plant and Equipment for further discussion. During the three and nine months ended September 30, 2015 , we fair valued the EquiPower and Duke Midwest acquisitions. See Note 3—Acquisitions for further discussion. Each of these valuations is classified as Level 3 within the fair value hierarchy. Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments recognized in our unaudited consolidated balance sheets. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of September 30, 2016 and December 31, 2015 , respectively. September 30, 2016 December 31, 2015 (amounts in millions) Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (1) Level 2 $ (2,081 ) $ (2,168 ) $ (2,077 ) $ (1,985 ) Tranche B-2 Term Loan, due 2020 (1) Level 2 $ (762 ) $ (779 ) $ (766 ) $ (754 ) 7.375% Senior Notes, due 2022 (1) Level 2 $ (1,731 ) $ (1,724 ) $ (1,729 ) $ (1,531 ) 5.875% Senior Notes, due 2023 (1) Level 2 $ (492 ) $ (450 ) $ (491 ) $ (404 ) 7.625% Senior Notes, due 2024 (1) Level 2 $ (1,236 ) $ (1,225 ) $ (1,235 ) $ (1,078 ) 7.00% Amortizing Notes, due 2019 (TEUs) (1) Level 2 $ (84 ) $ (88 ) $ — $ — Forward capacity agreement (1) Level 3 $ (203 ) $ (203 ) $ — $ — Inventory financing agreements Level 3 $ (136 ) $ (135 ) $ (136 ) $ (137 ) Equipment financing agreements (1) Level 3 $ (75 ) $ (75 ) $ (61 ) $ (61 ) Interest rate derivatives Level 2 $ (40 ) $ (40 ) $ (42 ) $ (42 ) Commodity-based derivative contracts (2) Various $ (81 ) $ (81 ) $ (154 ) $ (154 ) Common stock warrants Level 1 $ (2 ) $ (2 ) $ (7 ) $ (7 ) Dynegy Finance IV, Inc.: Tranche C Term Loan, due 2023 (1) Level 2 $ (1,995 ) $ (2,015 ) $ — $ — Genco: 7.00% Senior Notes Series H, due 2018 (1) Level 2 $ (284 ) $ (119 ) $ (276 ) $ (204 ) 6.30% Senior Notes Series I, due 2020 (1) Level 2 $ (218 ) $ (99 ) $ (213 ) $ (148 ) 7.95% Senior Notes Series F, due 2032 (1) Level 2 $ (226 ) $ (107 ) $ (225 ) $ (162 ) __________________________________________ (1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion. (2) Carrying amounts exclude $73 million and $106 million of cash posted as collateral, as of September 30, 2016 and December 31, 2015 , respectively.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	9 Months Ended
	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Accumulated Other Comprehensive Income	Note 7—Accumulated Other Comprehensive Income Changes in accumulated other comprehensive income, net of tax, by component, are as follows: Nine Months Ended September 30, (amounts in millions) 2016 2015 Beginning of period $ 19 $ 20 Other comprehensive income (loss) before reclassifications: Actuarial gain and plan amendments (net of tax of zero and $2, respectively) — 7 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively) (1) (4 ) (3 ) Net current period other comprehensive income (loss), net of tax (4 ) 4 End of period $ 15 $ 24 __________________________________________ (1) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 16—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory

Inventory	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Inventory	Note 8—Inventory A summary of our inventories is as follows: (amounts in millions) September 30, 2016 December 31, 2015 Materials and supplies $ 183 $ 178 Coal (1) 233 350 Fuel oil (1) 17 17 Emissions allowances (2) 14 51 Other — 1 Total $ 447 $ 597 __________________________________________ (1) At September 30, 2016 , approximately $47 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 13—Debt — Brayton Point Inventory Financing for further discussion. (2) At September 30, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt — Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment

Property, Plant and Equipment	9 Months Ended
	Sep. 30, 2016
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) September 30, 2016 December 31, 2015 Power generation $ 7,481 $ 8,178 Buildings and improvements 938 956 Office and other equipment 103 101 Property, plant and equipment 8,522 9,235 Accumulated depreciation (1,270 ) (888 ) Property, plant and equipment, net $ 7,252 $ 8,347 Impairments Stuart . In the third quarter 2016, we held strategic discussions with our partners, including the operator, concerning changes to our long term views of required maintenance and environmental capital expenditures, as well as discussing the profitability of the facility. As a result of these discussions, combined with consistently poor reliability and a determination that the facility would experience recurring negative cash flows, we concluded the facility will not recover its book value, thereby failing the recoverability step of an impairment analysis. Due to the recurring nature of the forecasted negative cash flows, we fair valued the asset at zero , resulting in an impairment charge of $55 million recorded to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 . The valuation is classified as Level 3 within the fair value hierarchy. Newton. On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance from the SO 2 annual emission rate limits provided in the Illinois Multi-Pollutant Standards (“MPS”). IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO 2 limits, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance. Capitalized costs not yet placed into service related to the project of $148 million were written-off and recorded to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 . Baldwin. On May 3, 2016, Dynegy announced the shutdown of Units 1 and 3 at its Baldwin power generation facility in Baldwin, Illinois over the next year. This decision was made after the units failed to recover their basic operating costs in the most recent MISO auction. On October 17, 2016, we shut down Baldwin Unit 3. Due to bilateral sales of incremental capacity for Planning Year 2017-2018, we will continue to operate Baldwin Unit 1 through the next Planning Year. As a result of these shutdowns, we performed an impairment analysis on all our MISO plants. We performed step one of the impairment analysis using undiscounted cash flows for the estimated useful lives of the facilities and determined the book value of the Baldwin facility would not be recovered. We performed step two of the impairment analysis using a DCF model, utilizing a 13 percent discount rate, and assuming normal operations for the estimated useful lives of the facilities. For the model, gross margin was based on forward commodity market prices obtained from third party quotations for the years 2016 through 2018. For the years 2019 through 2025, we used commodity and capacity price curves developed internally utilizing supply and demand factors. We also used management’s forecasts of operations and maintenance expense, general and administrative expense, and capital expenditures for the years 2016 through 2025 and assumed a 2.5 percent growth rate thereafter, based upon management’s view of future conditions. The model resulted in a fair value of the Baldwin facility of $97 million , resulting in an impairment charge of $645 million recorded to Impairments in our unaudited consolidated statements of operations for the nine months ended September 30, 2016 . The valuation is classified as Level 3 within the fair value hierarchy. Wood River. In the third quarter 2015, we impaired the book value of our Wood River facility and recorded a charge of $74 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2015 . Please read Note 9—Property, Plant and Equipment in our Form 10-K for further discussion.

Joint Ownership of Generating F

Joint Ownership of Generating Facilities	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Joint Ownership of Generating Facilities	Note 4—Unconsolidated Investment Equity Method Investment 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 1,580 MW natural gas-fired facility located in Elwood, Illinois. At September 30, 2016 and December 31, 2015 , our equity method investment included in our unaudited consolidated balance sheets was $173 million and $190 million , respectively. Upon the acquisition of our Elwood investment, we recognized basis differences in the net assets of approximately $89 million related to working capital, PP&E, debt, and intangibles. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. Holders of the debt of our unconsolidated investment do not have recourse to us and our other subsidiaries. For the three and nine months ended September 30, 2016 , we recorded $4 million and $7 million in equity earnings related to our investment in Elwood, respectively. For the three and nine months ended September 30, 2015 , we recorded $4 million and $1 million in equity losses related to our investment in Elwood, respectively. These equity earnings (losses) are included in Earnings (losses) from unconsolidated investment in our unaudited consolidated statements of operations. For the nine months ended September 30, 2016 , we received a distribution of $15 million , of which $14 million was considered a return of investment. For the nine months ended September 30, 2015 , we received a distribution of $11 million , of which $8 million was considered a return of investment. At September 30, 2016 and December 31, 2015 , we have $10 million and $3 million in accounts receivable due from Elwood, respectively, which is included in Accounts receivable, net in our unaudited consolidated balance sheets. On March 28, 2016, Dynegy Marketing and Trade, LLC (“DMT”), a subsidiary of Dynegy, entered into (i) an Asset Management Agreement and (ii) a Fuel Supply and Fuel Management Services Agreement with Elwood Energy. Under these agreements, DMT provides gas supply and management services to meet Elwood Energy’s fuel supply requirements. For the three and nine months ended September 30, 2016 , we recorded $15 million and $27 million in revenues related to these agreements, respectively, which is reflected in Revenues in our unaudited consolidated statements of operations. On August 3, 2016, Dynegy announced that it has entered into an agreement to sell its 50 percent equity interest in the Elwood Energy facility in Elwood, IL, to J-Power USA Development Co. Ltd. for approximately $173 million (“the Elwood Sale”). Under the agreement, Elwood will not make distributions to its members prior to the closing of the Elwood Sale. As a result, we recorded an impairment charge of $9 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 , to write down our investment in Elwood to the sales price. Additionally, approximately $35 million of previously posted collateral will be returned to Dynegy at closing. Upon approval from the FERC, the sale is expected to close in the fourth quarter of 2016. 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 additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our unaudited consolidated statements of operations. The following tables present the ownership interests of the jointly owned facilities as of September 30, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. September 30, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 206 $ (33 ) $ 3 $ 176 Stuart (1) 39.0 % $ — $ — $ — $ — Conesville (1) 40.0 % $ 61 $ (2 ) $ 5 $ 64 Zimmer 46.5 % $ 116 $ (21 ) $ 4 $ 99 Killen (1) 33.0 % $ 18 $ (1 ) $ 2 $ 19 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. In the third quarter 2016, we impaired the book value of the jointly owned Stuart facility and recorded a charge of $55 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 . Please read Note 9—Property, Plant and Equipment for further discussion.

Intangible Assets and Liabiliti

Intangible Assets and Liabilities	9 Months Ended
	Sep. 30, 2016
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Intangible Assets and Liabilities	Note 11—Intangible Assets and Liabilities The following table summarizes the components of our intangible assets and liabilities as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (187 ) $ 73 $ 260 $ (126 ) $ 134 Gas transport contracts 46 (37 ) 9 46 (16 ) 30 Total intangible assets $ 306 $ (224 ) $ 82 $ 306 $ (142 ) $ 164 Intangible Liabilities: Electricity contracts $ (28 ) $ 26 $ (2 ) $ (30 ) $ 19 $ (11 ) Coal contracts (93 ) 76 (17 ) (134 ) 82 (52 ) Coal transport contracts (104 ) 85 (19 ) (104 ) 64 (40 ) Gas transport contracts (41 ) 7 (34 ) (64 ) 27 (37 ) Total intangible liabilities $ (266 ) $ 194 $ (72 ) $ (332 ) $ 192 $ (140 ) Intangible assets and liabilities, net $ 40 $ (30 ) $ 10 $ (26 ) $ 50 $ 24 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Electricity contracts, net (1) $ 19 $ 21 $ 52 $ 53 Coal contracts, net (2) (9 ) (19 ) (32 ) (42 ) Coal transport contracts, net (2) (7 ) (9 ) (21 ) (24 ) Gas transport contracts, net (2) 1 (2 ) 18 (5 ) Total $ 4 $ (9 ) $ 17 $ (18 ) __________________________________________ (1) The amortization of these contracts is recognized in Revenues in our unaudited consolidated statements of operations. (2) The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Tangible Equity Units

Tangible Equity Units	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Tangible Equity Units	Note 12—Tangible Equity Units On June 21, 2016, we issued 4.6 million , 7 percent TEUs at $100 per unit and received proceeds of $446 million , net of issuance costs of $14 million . During the third quarter of 2016, we incurred an additional $3 million in issuance costs. Each TEU is comprised of: (i) a prepaid stock purchase contract (“SPC”) issued by Dynegy, and (ii) an amortizing note (“Amortizing Note”), with an initial principal amount of $18.95 that pays an equal quarterly cash installment of $1.75 per Amortizing Note on January 1, April 1, July 1, and October 1 of each year, with the exception of the first installment payment of $1.94 due on October 1, 2016. In the aggregate, the annual quarterly cash installments will be equivalent to a 7 percent cash payment per year. Each installment cash payment constitutes a payment of interest and a partial repayment of principal. Each TEU may be separated by a holder into its constituent SPC and Amortizing Note after the initial issuance date of the TEUs, and the separate components may be combined to create a TEU after the initial issuance date, in accordance with the terms of the SPC. The TEUs are listed on the New York Stock Exchange under the symbol “DYNC”. We allocated the proceeds from the issuance of the TEUs, including other fees and expenses, to equity and debt based on the relative fair value of the respective components of each TEU as follows: (in millions, except price per TEU) SPC Amortizing Note Total Price per TEU $ 81 $ 19 $ 100 Gross proceeds $ 373 $ 87 $ 460 Less: Issuance costs (14 ) (3 ) (17 ) Net proceeds $ 359 $ 84 $ 443 The fair value of the SPCs was recorded as additional paid in capital, net of issuance costs. The fair value of the Amortizing Notes was recorded as debt, with deferred financing costs recorded as a reduction of the carrying amount of the debt in our unaudited consolidated balance sheet. Deferred financing costs related to the Amortizing Notes will be amortized through the maturity date using the effective interest rate method. Unless settled early at the holder’s or Dynegy’s election or redeemed by Dynegy in connection with an acquisition termination redemption, on July 1, 2019, Dynegy will deliver to the SPC holders a number of shares of common stock based on the 20 day volume-weighted average price (“VWAP”) of our common stock as follows: VWAP of Dynegy Common Stock Common Shares Issued Equal to or greater than $19.92 5.0201 shares (minimum settlement rate) Less than $19.92, but greater than $16.13 $100 divided by VWAP Less than or equal to $16.13 6.1996 shares (maximum settlement rate) In addition, on any business day during the period beginning on, and including, the business day immediately following the date of initial issuance of the TEUs to, but excluding, the third business day immediately preceding the mandatory settlement date, any holder of an SPC may settle any or all of its SPCs early, and Dynegy will deliver a number of shares of Common Stock equal to the minimum settlement rate. Additionally, the SPCs may be redeemed in the event of a fundamental change or under an acquisition termination event, both as defined in the SPC.

Debt

Debt	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Debt	Note 13—Debt A summary of our long-term debt is as follows: (amounts in millions) September 30, 2016 December 31, 2015 Secured Obligations: Dynegy Inc.: Tranche B-2 Term Loan, due 2020 $ 774 $ 780 Revolving Facility — — Forward Capacity Agreement 219 — Inventory Financing Agreements 136 136 Dynegy Finance IV, Inc.: Tranche C Term Loan, due 2023 (1) 2,000 — Subtotal secured obligations 3,129 916 Unsecured Obligations: Dynegy Inc.: 7.00% Amortizing Notes, due 2019 (TEUs) 87 — 6.75% Senior Notes, due 2019 2,100 2,100 7.375% Senior Notes, due 2022 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 1,250 1,250 Equipment Financing Agreements 100 75 Subtotal unsecured obligations 5,787 5,675 Total Dynegy Inc. and Dynegy Finance IV, Inc. 8,916 6,591 Genco Unsecured Obligations: 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 Total Genco (2) 825 825 Total debt obligations 9,741 7,416 Unamortized debt discounts and issuance costs (3) (218 ) (207 ) 9,523 7,209 Less: Current maturities, including unamortized debt discounts and issuance costs, net 167 80 Total Long-term debt $ 9,356 $ 7,129 __________________________________________ (1) At September 30, 2016 , the Tranche C Term Loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our unaudited consolidated balance sheet. Upon the closing of the Delta Transaction, this debt obligation will become Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion. (2) On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes. See Note 21—Subsequent Events —Genco Debt Restructure for further discussion. (3) Includes $97 million and $111 million of unamortized debt discounts as of September 30, 2016 and December 31, 2015 , respectively, relating to the Genco unsecured obligations. Credit Agreement and Finance IV Credit Agreement As of September 30, 2016 , we had a $2.225 billion credit agreement, as amended, that consisted of (i) an $800 million seven -year senior secured term loan facility (the “Tranche B-2 Term Loan”) and (ii) $1.425 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan the “Credit Agreement”). Additionally, we had a $2.0 billion , seven -year senior Tranche C Term Loan, under the Finance IV Credit Agreement, as defined below. At September 30, 2016 , there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $327 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 September 30, 2016 . Finance IV Credit Agreement . On June 27, 2016 (the “Term Loan Closing Date”), Finance IV entered into a term loan credit agreement which provides for a $2.0 billion , seven -year Tranche C Term Loan, and matures on June 27, 2023. The Tranche C Term Loan bears interest at either (i) 4 percent per annum plus LIBOR, subject to a floor of one percent with respect to any LIBOR Loan or (ii) 3 percent per annum plus the Base Rate with respect to any Base Rate Loan. Amounts available under the Tranche C Term Loan were fully drawn on the Term Loan Closing Date, and the net proceeds were placed into escrow (see “Escrow Agreement” described below) pending the consummation of the Delta Transaction. The Finance IV Credit Agreement contains limited events of default and affirmative covenants and one negative covenant, which restricts the activities of Finance IV to those primarily relating to the Delta Transaction and financing. The obligations of Finance IV under the Finance IV Credit Agreement are secured by the related amounts placed in escrow from time to time. Escrow Agreement. On the Term Loan Closing Date, Finance IV borrowed the full amount of the Tranche C Term Loan and placed the net proceeds into an escrow account (the “Escrow Account”). Additionally, Dynegy initially contributed $70 million into escrow so that the aggregate funds in the Escrow Account would be sufficient to repay the Tranche C Term Loan plus any interest that may accrue for a period of six months from the Term Loan Closing Date. Pursuant to the Escrow Agreement, interest payments on the Tranche C Term Loan will be paid from the amounts in the escrow account until the release of funds on the Escrow Release Date. To date, $26 million has been released from escrow for interest payments. As of September 30, 2016 , we had $2.0 billion classified as long-term Restricted cash and $45 million classified as short-term Restricted cash in our unaudited consolidated balance sheet related to the Escrow Agreement. The $45 million includes a payment to the escrow account of (i) $25 million of remaining pre-funded interest and interest income earned, and (ii) $20 million of pre-funded original issue discount which is contingent upon the closing of the Delta Transaction. Upon the release of funds from escrow upon the satisfaction of the Delta Transaction Escrow Conditions, as defined in the Finance IV Credit Agreement (the “Escrow Release Date”), Finance IV will merge with and into Dynegy, with Dynegy as the surviving entity, and Dynegy will use the amounts released from escrow to fund a portion of the Delta Transaction. The Finance IV Credit Agreement provides that, upon the effectiveness of the Conversion and Deemed Issuance, as defined in the Finance IV Credit Agreement, the latter will (a) cease to be of force or effect and (b) be superseded by the provisions of the Credit Agreement, as amended by the Third Amendment. If the Delta Transaction Escrow Conditions are not satisfied on or prior to February 24, 2017 (the “Delta Transaction Deadline”) or if the Delta Stock Purchase Agreement is terminated or Finance IV has determined that the Delta Transaction will not be consummated on or before the Delta Transaction Deadline, the escrow agent will, within one business day, liquidate all escrowed property held in escrow and release all amounts to the lenders under the Finance IV Credit Agreement. Credit Agreement Third Amendment. The Third Amendment provides, upon the Escrow Release Date, for (i) a $75 million Incremental Tranche B Revolver to the Revolving Facility, which has terms substantially the same as the terms of the Revolving Facility and will mature on April 2, 2020 and (ii) an incremental $2.0 billion , seven -year senior secured Tranche C Term Loan which has terms substantially the same as the Finance IV Credit Agreement discussed above. In addition, as requested by the Seller in the Delta Transaction, on June 27, 2016, Dynegy, the guarantors, the lenders and other parties thereto entered into a waiver to the Credit Agreement (the “Waiver”), providing a waiver from the lenders party thereto of the Incremental Ratio Tests (as defined in the Credit Agreement) and confirmation that notwithstanding the terms of the Credit Agreement or other related Credit Document (as defined in the Credit Agreement), Dynegy may incur the Tranche C Term Loan and the Incremental Tranche B Revolver without regard to the satisfaction of the Incremental Ratio Tests and no default or event of default will occur as a result of any breach of the Incremental Ratio Tests. Upon the Escrow Release Date, the Credit Agreement will be comprised of (i) an $800 million , seven -year Tranche B-2 Term Loan, (ii) a $2.0 billion , seven -year Tranche C Term Loan, and (iii) a $1.5 billion Revolving Facility consisting of three tranches of revolving commitments including: (a) a $475 million tranche which will mature on April 23, 2018, (b) a $350 million tranche which will mature April 1, 2020, and (c) a $675 million tranche, which includes the Incremental Tranche B Revolver and will mature on April 2, 2020. Interest Rate Swaps. During 2013, we amended our interest rate swaps to more closely match the terms of our Tranche B-2 Term Loan. The swaps have an aggregate notional value of approximately $771 million at an average fixed rate of 3.19 percent with a floor of one percent , and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the swaps are reflected as a financing activity in our unaudited consolidated statements of cash flows. Letter of Credit Facilities Dynegy has an LC Reimbursement Agreement with an issuing bank, and its affiliate (the “Lender”), for an LC in an amount not to exceed $55 million . The facility expires in September 2017. At September 30, 2016 , there was $55 million outstanding under this LC. Illinois Power Marketing Company (“IPM”) has LC and reimbursement agreements with issuing banks in which the issuing banks agree to issue standby LCs in stated amounts not to exceed $50 million , in aggregate, to support performance obligations and other general corporate activities of IPM and IPRG. As of September 30, 2016 , there were $30 million in LCs outstanding under these facilities. One of the IPM LC facilities is fully collateralized by cash, and as of September 30, 2016 , IPM had $19 million deposited with the issuing bank. On February 24, 2016, Dynegy entered into a bilateral letter of credit facility commitment letter with an issuing bank for $50 million , which is contingent upon the closing of the Delta Transaction. Forward Capacity Agreement On March 18, 2016, we entered into a bilateral contract with a financial institution to sell a portion of our forward cleared PJM capacity auction volumes. In exchange, we received $198 million in cash proceeds during the first quarter of 2016. The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2017-2018 and 2018-2019 in the amounts of $110 million and $109 million , respectively. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. The transaction is accounted for as a debt issuance of $219 million with an implied interest rate of 4.45 percent . Inventory Financing Agreements Brayton Point Inventory Financing. In connection with the EquiPower Acquisition, we assumed an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories at our Brayton Point facility, consisting of a debt obligation for existing and subsequent inventories, as well as a $15 million line of credit. Balances in excess of the $15 million line of credit are cash collateralized. As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation costs, and other expenses. The debt obligation increases for 85 percent of the total cost of the coal and for 90 percent of the total cost of the fuel oil. The line of credit increases for the remaining 15 percent and 10 percent for coal and oil costs, respectively. We repay the debt obligation and line of credit from revenues received, at the then market price, for the amount of the materials consumed, on a weekly basis. As of September 30, 2016 , there was $58 million outstanding under this agreement. Both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3 -month LIBOR plus 5.6 percent . An availability fee is calculated on a per annum rate of 0.25 percent . Additionally, we had collateral postings of approximately $3 million . The Inventory Financing Agreement terminates, and the remaining obligation, if any, becomes due and payable, on May 31, 2017. Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. We are obligated to repurchase a portion of the inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent . As of September 30, 2016 , there was $78 million , in aggregate, outstanding under these agreements. Amortizing Notes On June 21, 2016, in connection with the issuance of the TEUs, Dynegy issued the Amortizing Notes with a principal amount of approximately $87 million . The Amortizing Notes mature on July 1, 2019. Each installment payment of $1.75 (or, in the case of the installment payment due on October 1, 2016, $1.94 ) per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7 percent . Interest will be calculated on the basis of a 360 day year consisting of twelve 30 day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the Indenture. Please read Note 12—Tangible Equity Units for further discussion. The Indenture limits, among other things, the ability of Dynegy to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if Dynegy elects to settle the SPCs early or to redeem the SPCs in connection with a termination of the Delta Stock Purchase Agreement, then the holders of the Amortizing Notes will have the right to require Dynegy to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The Indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness, the failure to satisfy covenants, and specified events of bankruptcy and insolvency. Dynegy Senior Notes As of September 30, 2016 , we had $5.6 billion in senior notes that consisted of (i) $2.1 billion , 6.75 percent senior notes, due 2019, (ii) $1.75 billion , 7.375 percent senior notes, due 2022, (iii) $500 million , 5.875 percent senior notes, due 2023, and (iv) $1.25 billion , 7.625 percent senior notes, due 2024 (collectively, the “Senior Notes”). On October 11, 2016, Dynegy issued in a private placement transaction $750 million of 8 percent unsecured senior notes due 2025. See Note 21—Subsequent Events —2025 Senior Notes for further discussion. 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 unaudited consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $75 million . The $25 million discount is currently amortized as interest expense over the life of the payments. Genco Senior Notes Genco’s approximately $825 million in aggregate principal amount of unsecured senior notes (the “Genco Senior Notes”) are an obligation of Genco, a subsidiary of IPH. 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. The Genco Senior Notes are non-recourse to Dynegy. Please read Note 1—Basis of Presentation and Organization for further discussion. Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. Genco’s debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness. The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% __________________________________________ (1) As of the date of a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. (2) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from external, third-party sources are included in the definition of indebtedness and are subject to these incurrence tests. Based on September 30, 2016 calculations, Genco did not meet the ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources. On October 14, 2016, we entered into an RSA with Genco and the Ad Hoc Group to restructure the Genco Senior Notes. See Note 21—Subsequent Events —Genco Debt Restructure for further discussion. As a result of this restructure, Moody’s downgraded Genco’s Senior Unsecured credit rating from Caa3 to Ca.

Commitments and Contingencies

Commitments and Contingencies	9 Months Ended
	Sep. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 14—Commitments and Contingencies Legal Proceedings Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, the nature of damages sought, and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals, and that such differences could be material. In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations, or cash flows. Gas Index Pricing Litigation. We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. At this time we cannot reasonably estimate a potential loss. Illinova Generating Company Arbitration. In May 2007, our subsidiary Illinova Generating Company (“IGC”) received an adverse award in an arbitration brought by Ponderosa Pine Energy, LLC (“PPE”). The award required IGC to pay PPE $17 million , which IGC paid in June 2007 under protest while simultaneously seeking to vacate the award. On May 23, 2014, the Texas Supreme Court vacated the arbitration award based upon the evident partiality of one of the arbitrators. On November 20, 2014, PPE initiated a new arbitration against IGC and its co-respondents, but the Dallas District Court enjoined the arbitration from proceeding against IGC while any dispute over IGC’s $17 million payment remains pending. On December 16, 2014, the Dallas District Court entered a judgment requiring the return of the $17 million to IGC and an additional $2.5 million payment to IGC for interest. PPE paid the $17 million principal and the $2.5 million in interest to IGC. On July 14, 2016, the Dallas Court of Appeals affirmed the judgment. PPE’s deadline to appeal the judgment to the Texas Supreme Court has expired. We recognized a gain of $20 million which is included in Other income and expense, net in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 . Other Contingencies MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint. On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. 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 PRA, and stated that those issues remain under consideration and will be addressed in a future order. New Source Review and CAA Matters. New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006, and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting, and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV. Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. As of June 1, 2016, our Wood River facility has been retired. CAA Notices of Violation. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we jointly own but do not operate. Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We have filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. The District Court has not yet scheduled the remedy phase of the case. We dispute the allegations and will defend the case vigorously. Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters. Stuart National Pollutant Discharge Elimination System (“NPDES”) Permit Appeal. In January 2013, the Ohio EPA reissued the NPDES permit for the jointly owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter. Coal Segment Groundwater . In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities. At Baldwin, with approval of the IEPA, we performed a comprehensive evaluation of the Baldwin Coal Combustion Residuals (“CCR”) surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the IEPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. In April 2016, we submitted closure and post-closure care plans to the IEPA for the Baldwin old east, east, and west fly ash CCR surface impoundments. The IEPA has approved our plans. We initiated an investigation at Baldwin in 2011 at the request of the IEPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the IEPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. Based on the data and groundwater flows, we do not believe that the exceedances are attributable to the Baldwin CCR surface impoundment system. At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the IEPA in 2012. Our hydrogeologic investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrate offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the IEPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await IEPA action on our proposed corrective action plans. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million . If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the IEPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill. In August 2016, IEPA approved the report. If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments in 2009. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities. In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment. The preliminary estimated cost for closure of the west CCR surface impoundment, including post-closure monitoring, is approximately $5 million , which is reflected in our AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014, and await IEPA action. In response to the Baldwin report, we notified the EPA in 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs. Other Commitments In conducting our operations, we 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, and power generation assets. Environmental Compliance Obligations. On September 2, 2016, IPH and Ameren Energy Medina Valley Cogen, LLC filed a motion with the IPCB to terminate the variance from the SO 2 annual emission rate limits provided in the MPS. IPH retired Newton Unit 2 on September 15, 2016. This retirement, along with the use of dispatch management, will allow IPH to continue to comply with the MPS SO 2 limits, thereby eliminating the need for the variance. As a result, the FGD systems construction project at our Newton generation facility was terminated. On October 27, 2016, the IPCB granted the motion to terminate the variance. Indemnifications and Guarantees In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications, and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. We have accrued no amounts with respect to the indemnifications as of September 30, 2016 because none were probable of occurring, nor could they be reasonably estimated. Delta Transaction Guarantee. In connection with the Delta Stock Purchase Agreement executed on June 27, 2016, Dynegy entered into a guarantee agreement under which Dynegy has agreed to guarantee 100 percent of the Purchaser’s obligation to pay the reverse termination fee of $132 million if such fee becomes payable under the terms and conditions of the Delta Stock Purchase Agreement.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 15—Income Taxes We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant, unusual, or extraordinary transactions. Income taxes for significant, unusual, or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. For the three and nine months ended September 30, 2016 , we recorded a tax benefit of $1 million and expense of $6 million , respectively for the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance. In addition, for the nine months ended September 30, 2016 , we recorded a tax benefit of $3 million for the additional release of our valuation allowance as a result of increased net deferred tax liabilities related to the final purchase price allocation for the EquiPower Acquisition and a $14 million state tax expense as a result of a change to our corporate tax structure. For the three and nine months ended September 30, 2015 , we recognized a tax charge of $21 million and a tax benefit of $459 million , respectively. This charge and benefit were related to the release of our deferred tax valuation allowance caused by the initial, and subsequent adjustment to, allocation of part of the EquiPower Acquisition purchase price to deferred tax liabilities. In addition, for the three and nine months ended September 30, 2015 , we recorded a tax charge of $7 million and tax benefit of $14 million respectively for discreet items, including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance. As of September 30, 2016 , we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future.

Pension and Other Post-Employme

Pension and Other Post-Employment Benefit Plans	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Pension and Other Post-Employment Benefit Plans	Note 16—Pension and Other Post-Employment Benefit Plans We sponsor and administer defined benefit plans and defined contribution plans for the benefit of our employees and also provide other post-employment benefits to retirees who meet age and service requirements, which are further described in Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K. In August 2015, we finalized certain new collective bargaining agreements that resulted in amendments to certain pension and other post-employment benefit plans. As a result of these amendments, we remeasured our benefit obligations and the funded status of the affected plans using inputs as of July 31, 2015. We recorded a gain through other comprehensive income and decreased our net liability by approximately $15 million during the third quarter of 2015. Components of Net Periodic Benefit Cost (Gain). The components of net periodic benefit cost (gain) were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 4 $ 4 $ — $ 1 Interest cost on projected benefit obligation 5 4 1 1 Expected return on plan assets (5 ) (6 ) (1 ) (1 ) Amortization of prior service credit (1 ) — (1 ) (1 ) Net periodic benefit cost (gain) $ 3 $ 2 $ (1 ) $ — Pension Benefits Other Benefits Nine Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 12 $ 11 $ — $ 1 Interest cost on projected benefit obligation 15 13 3 3 Expected return on plan assets (17 ) (17 ) (3 ) (3 ) Amortization of prior service credit (1 ) (1 ) (3 ) (2 ) Net periodic benefit cost (gain) $ 9 $ 6 $ (3 ) $ (1 )

Capital Stock

Capital Stock	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Capital Stock	Note 17—Capital Stock Dividends We pay quarterly dividends on our mandatory convertible preferred stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For the three months ended September 30, 2016 and 2015 , we paid $5 million in dividends on August 1, 2016 and August 3, 2015, respectively. For the nine months ended September 30, 2016 and 2015 , we paid an aggregate of $16 million and $17 million in dividends, respectively. On September 30, 2016, our Board of Directors declared a dividend on our mandatory convertible preferred stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the period beginning on August 1, 2016 and ending on October 31, 2016. Such dividends were paid on November 1, 2016 to stockholders of record as of October 15, 2016. TEUs On June 21, 2016, pursuant to a registered public offering, we issued 4.6 million , 7 percent TEUs at $100 per unit. Each TEU was comprised of a prepaid stock purchase contract and an amortizing note which were accounted for as separate instruments. Please read Note 12—Tangible Equity Units for further discussion. Share Repurchase Program 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 September 30, 2015, we had repurchased 4,996,299 shares at an aggregate cost of $127 million . Please read Note 17—Capital Stock—Common Stock in our Form 10-K for further discussion.

Earnings (Loss) Per Share

Earnings (Loss) Per Share	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Earnings (Loss) Per Share	Note 18—Earnings (Loss) Per Share Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if-converted method. Please read Note 17—Capital Stock in our Form 10-K and Note 12—Tangible Equity Units for further discussion. The basic and diluted earnings (loss) per share from continuing operations attributable to our common stockholders during the three and nine months ended September 30, 2016 and 2015 is shown in the following table: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2016 2015 2016 2015 Income (loss) from continuing operations $ (249 ) $ (24 ) $ (1,062 ) $ 181 Less: Net loss attributable to noncontrolling interest — — (2 ) (3 ) Income (loss) from continuing operations attributable to Dynegy Inc. (249 ) (24 ) (1,060 ) 184 Less: Dividends on preferred stock 5 5 16 16 Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic earnings (loss) per share (254 ) (29 ) (1,076 ) 168 Add: Dividends on preferred stock (1) — — — 16 Adjusted income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for diluted earnings (loss) per share $ (254 ) $ (29 ) $ (1,076 ) $ 184 Basic weighted-average shares (2) 140 126 126 126 Effect of dilutive securities (3) — — — 14 Diluted weighted-average shares 140 126 126 140 Earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders: Basic (2) $ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.33 Diluted (3) $ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.31 __________________________________________ (1) Excluded for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015 due to a net loss from continuing operations for the respective periods. (2) For the three and nine months ended September 30, 2016 , the TEUs are assumed to be outstanding at the minimum settlement amount, or 23,092,460 shares, for weighted-average shares for basic earnings (loss) per share. Please read Note 12—Tangible Equity Units for further discussion. (3) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015 . For the three and nine months ended September 30, 2016 and 2015 , the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive: Three Months Ended September 30, Nine Months Ended September 30, (in millions of shares) 2016 2015 2016 2015 Stock options 2.8 1.8 2.8 — Restricted stock units 1.3 1.5 1.3 — Performance stock units 1.2 0.6 1.2 — Warrants 15.6 15.6 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 12.9 12.9 — Prepaid stock purchase contract (TEUs) 5.4 — 5.4 — Total 39.2 32.4 39.2 15.6

Condensed Consolidating Financi

Condensed Consolidating Financial Information	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Financial Information	Note 19—Condensed Consolidating Financial Information The following condensed consolidating financial statements present the financial information of (i) Dynegy (“Parent”), which is the parent and issuer of the $5.6 billion Senior Notes, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Dynegy, (iii) the non-guarantor subsidiaries of Dynegy, and (iv) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis. The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the Senior Notes. Not all of Dynegy’s subsidiaries guarantee the Senior Notes including Dynegy’s indirect, wholly-owned subsidiary, IPH. Please read Note 13—Debt for further discussion. These statements should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. For purposes of the unaudited condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of September 30, 2016 and December 31, 2015 . Condensed Consolidating Balance Sheet as of September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 1,248 $ 69 $ 141 $ — $ 1,458 Restricted cash — — 85 — 85 Accounts receivable, net 115 2,383 135 (2,259 ) 374 Inventory — 234 213 — 447 Other current assets 11 235 31 (2 ) 275 Total Current Assets 1,374 2,921 605 (2,261 ) 2,639 Property, plant and equipment, net — 6,901 351 — 7,252 Investment in affiliates 12,335 173 — (12,335 ) 173 Restricted cash — — 2,000 — 2,000 Goodwill — 799 — — 799 Other long-term assets 4 112 45 — 161 Intercompany note receivable — — 3 (3 ) — Total Assets $ 13,713 $ 10,906 $ 3,004 $ (14,599 ) $ 13,024 Current Liabilities Accounts payable $ 1,745 $ 226 $ 551 $ (2,259 ) $ 263 Other current liabilities 224 293 133 (2 ) 648 Total Current Liabilities 1,969 519 684 (2,261 ) 911 Debt, long-term portion, net 6,355 288 2,713 — 9,356 Intercompany note payable 3,042 — — (3,042 ) — Other long-term liabilities 136 287 130 (3 ) 550 Total Liabilities 11,502 1,094 3,527 (5,306 ) 10,817 Stockholders’ Equity Dynegy Stockholders’ Equity 2,211 12,854 (519 ) (12,335 ) 2,211 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,211 9,812 (519 ) (9,293 ) 2,211 Noncontrolling interest — — (4 ) — (4 ) Total Equity 2,211 9,812 (523 ) (9,293 ) 2,207 Total Liabilities and Equity $ 13,713 $ 10,906 $ 3,004 $ (14,599 ) $ 13,024 Condensed Consolidating Balance Sheet as of 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 13 335 55 (14 ) 389 Total Current Assets 839 2,263 574 (1,744 ) 1,932 Property, plant and equipment, net — 7,813 534 — 8,347 Investment in affiliates 13,017 190 — (13,017 ) 190 Other long-term assets 10 133 50 — 193 Goodwill — 797 — — 797 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459 Current Liabilities Accounts payable $ 1,388 $ 238 $ 396 $ (1,730 ) $ 292 Other current liabilities 92 277 162 (14 ) 517 Total Current Liabilities 1,480 515 558 (1,744 ) 809 Debt, long-term portion, net 6,293 122 714 — 7,129 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 10,962 954 1,427 (4,803 ) 8,540 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459 Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 919 $ 267 $ (2 ) $ 1,184 Cost of sales, excluding depreciation expense — (501 ) (161 ) 2 (660 ) Gross margin — 418 106 — 524 Operating and maintenance expense — (152 ) (66 ) — (218 ) Depreciation expense — (147 ) (16 ) — (163 ) Impairments — (64 ) (148 ) — (212 ) General and administrative expense (2 ) (28 ) (11 ) — (41 ) Acquisition and integration costs (5 ) — (2 ) — (7 ) Other — (1 ) 1 — — Operating income (loss) (7 ) 26 (136 ) — (117 ) Earnings from unconsolidated investment — 4 — — 4 Equity in losses from investments in affiliates (153 ) — — 153 — Interest expense (112 ) (5 ) (50 ) 1 (166 ) Other income and expense, net 23 5 2 (1 ) 29 Income (loss) before income taxes (249 ) 30 (184 ) 153 (250 ) Income tax benefit (expense) — 37 (36 ) — 1 Net income (loss) (249 ) 67 (220 ) 153 (249 ) Less: Net loss attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (249 ) $ 67 $ (220 ) $ 153 $ (249 ) Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,517 $ 696 $ (2 ) $ 3,211 Cost of sales, excluding depreciation expense — (1,295 ) (405 ) 2 (1,698 ) Gross margin — 1,222 291 — 1,513 Operating and maintenance expense — (503 ) (192 ) — (695 ) Depreciation expense — (433 ) (61 ) — (494 ) Impairments — (709 ) (148 ) — (857 ) General and administrative expense (5 ) (87 ) (25 ) — (117 ) Acquisition and integration costs (8 ) (3 ) 3 — (8 ) Other — (1 ) (15 ) — (16 ) Operating loss (13 ) (514 ) (147 ) — (674 ) Earnings from unconsolidated investment — 7 — — 7 Equity in losses from investments in affiliates (718 ) — — 718 — Interest expense (355 ) (9 ) (87 ) 2 (449 ) Other income and expense, net 26 20 16 (2 ) 60 Loss before income taxes (1,060 ) (496 ) (218 ) 718 (1,056 ) Income tax benefit (expense) — 30 (36 ) — (6 ) Net loss (1,060 ) (466 ) (254 ) 718 (1,062 ) Less: Net loss attributable to noncontrolling interest — — (2 ) — (2 ) Net loss attributable to Dynegy Inc. $ (1,060 ) $ (466 ) $ (252 ) $ 718 $ (1,060 ) Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 878 $ 249 $ 105 $ 1,232 Cost of sales, excluding depreciation expense — (369 ) (147 ) (105 ) (621 ) Gross margin — 509 102 — 611 Operating and maintenance expense — (154 ) (65 ) — (219 ) Depreciation expense — (149 ) (25 ) — (174 ) Impairments — (74 ) — — (74 ) General and administrative expense 3 (26 ) (6 ) — (29 ) Acquisition and integration costs — (8 ) — — (8 ) Operating income 3 98 6 — 107 Losses from unconsolidated investment — (4 ) — — (4 ) Equity in earnings from investments in affiliates 53 — — (53 ) — Interest expense (127 ) — (18 ) — (145 ) Other income and expense, net 47 (1 ) — — 46 Income (loss) before income taxes (24 ) 93 (12 ) (53 ) 4 Income tax benefit (expense) — (45 ) 17 — (28 ) Net income (loss) (24 ) 48 5 (53 ) (24 ) Less: Net loss attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (24 ) $ 48 $ 5 $ (53 ) $ (24 ) Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,186 $ 672 $ (4 ) $ 2,854 Cost of sales, excluding depreciation expense — (1,080 ) (418 ) 4 (1,494 ) Gross margin — 1,106 254 — 1,360 Operating and maintenance expense — (385 ) (195 ) — (580 ) Depreciation expense — (352 ) (61 ) — (413 ) Impairments — (74 ) — — (74 ) General and administrative expense — (69 ) (25 ) — (94 ) Acquisition and integration costs — (121 ) — — (121 ) Other — (1 ) — — (1 ) Operating income (loss) — 104 (27 ) — 77 Losses from unconsolidated investment — (1 ) — — (1 ) Equity in earnings from investments in affiliates 500 — — (500 ) — Interest expense (361 ) — (52 ) — (413 ) Other income and expense, net 45 — — — 45 Income (loss) before income taxes 184 103 (79 ) (500 ) (292 ) Income tax benefit — 473 — — 473 Net income (loss) 184 576 (79 ) (500 ) 181 Less: Net loss attributable to noncontrolling interest — — (3 ) — (3 ) Net income (loss) attributable to Dynegy Inc. $ 184 $ 576 $ (76 ) $ (500 ) $ 184 Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (249 ) $ 67 $ (220 ) $ 153 $ (249 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (1 ) — (1 ) — (2 ) Other comprehensive loss from investment in affiliates (1 ) — — 1 — Other comprehensive loss, net of tax (2 ) — (1 ) 1 (2 ) Comprehensive income (loss) (251 ) 67 (221 ) 154 (251 ) Less: Comprehensive income (loss) attributable to noncontrolling interest — — — — — Total comprehensive income (loss) attributable to Dynegy Inc. $ (251 ) $ 67 $ (221 ) $ 154 $ (251 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (1,060 ) $ (466 ) $ (254 ) $ 718 $ (1,062 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (3 ) — (1 ) — (4 ) Other comprehensive loss from investment in affiliates (1 ) — — 1 — Other comprehensive loss, net of tax (4 ) — (1 ) 1 (4 ) Comprehensive loss (1,064 ) (466 ) (255 ) 719 (1,066 ) Less: Comprehensive loss attributable to noncontrolling interest — — (2 ) — (2 ) Total comprehensive loss attributable to Dynegy Inc. $ (1,064 ) $ (466 ) $ (253 ) $ 719 $ (1,064 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (24 ) $ 48 $ 5 $ (53 ) $ (24 ) Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of tax of $2 6 — 7 — 13 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — (1 ) Other comprehensive income from investment in affiliates 7 — — (7 ) — Other comprehensive income, net of tax 12 — 7 (7 ) 12 Comprehensive income (loss) (12 ) 48 12 (60 ) (12 ) Less: Comprehensive income attributable to noncontrolling interest 1 — 1 (1 ) 1 Total comprehensive income (loss) attributable to Dynegy Inc. $ (13 ) $ 48 $ 11 $ (59 ) $ (13 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 184 $ 576 $ (79 ) $ (500 ) $ 181 Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of tax of $2 1 — 7 — 8 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (3 ) — — — (3 ) Other comprehensive income from investment in affiliates 7 — — (7 ) — Other comprehensive income, net of tax 5 — 7 (7 ) 5 Comprehensive income (loss) 189 576 (72 ) (507 ) 186 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 — (2 ) (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 188 $ 576 $ (70 ) $ (506 ) $ 188 Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (155 ) $ 780 $ 24 $ — $ 649 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (227 ) (32 ) — (259 ) Increase in restricted cash — — (2,045 ) — (2,045 ) Net intercompany transfers 670 — — (670 ) — Distributions from unconsolidated affiliate — 14 — — 14 Other investing — 10 — — 10 Net cash provided by (used in) investing activities 670 (203 ) (2,077 ) (670 ) (2,280 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 84 198 1,995 — 2,277 Repayments of borrowings (6 ) (15 ) — — (21 ) Proceeds from issuance of equity, net of issuance costs 359 — — — 359 Preferred stock dividends paid (16 ) — — — (16 ) Interest rate swap settlement payments (13 ) — — — (13 ) Net intercompany transfers — (785 ) 115 670 — Other financing (2 ) — — — (2 ) Net cash provided by (used in) financing activities 406 (602 ) 2,110 670 2,584 Net increase (decrease) in cash and cash equivalents 921 (25 ) 57 — 953 Cash and cash equivalents, beginning of period 327 94 84 — 505 Cash and cash equivalents, end of period $ 1,248 $ 69 $ 141 $ — $ 1,458 Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (141 ) $ 502 $ (59 ) $ — $ 302 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (8 ) (122 ) (41 ) — (171 ) Acquisition, net of cash acquired (6,207 ) 29 100 — (6,078 ) Decrease in restricted cash 5,148 — — — 5,148 Net intercompany transfers 349 — — (349 ) — Distributions from unconsolidated affiliate — 8 — — 8 Other investing — (6 ) — — (6 ) Net cash provided by (used in) investing activities (718 ) (91 ) 59 (349 ) (1,099 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs (31 ) 78 10 — 57 Repayments of borrowings (6 ) (23 ) — — (29 ) Proceeds from issuance of equity, net of issuance costs (6 ) — — — (6 ) Preferred stock dividends paid (17 ) — — — (17 ) Interest rate swap settlement payments (13 ) — — — (13 ) Net intercompany transfers — (344 ) (5 ) 349 — Repurchase of common stock (127 ) — — — (127 ) Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (204 ) (289 ) 5 349 (139 ) Net increase (decrease) in cash and cash equivalents (1,063 ) 122 5 — (936 ) Cash and cash equivalents, beginning of period 1,642 54 174 — 1,870 Cash and cash equivalents, end of period $ 579 $ 176 $ 179 $ — $ 934

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Segment Information	Note 20—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 IPRG, which also own, directly and indirectly, certain of our coal-fired power generation facilities. IPH also includes our Homefield Energy retail business in Illinois. IPH and its direct and indirect subsidiaries, and Genco and its direct and indirect subsidiaries, are each organized into ring-fenced groups in order to maintain corporate separateness. The Gas segment includes substantially all of our natural gas-fired power generation facilities. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2016 and 2015 is presented below: Segment Data as of and for the Three Months Ended September 30, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 388 $ 241 $ 539 $ — $ 1,168 Intercompany and affiliate revenues — 1 15 — 16 Total revenues $ 388 $ 242 $ 554 $ — $ 1,184 Depreciation expense $ (27 ) $ (7 ) $ (128 ) $ (1 ) $ (163 ) Impairments (55 ) (148 ) (9 ) — (212 ) General and administrative expense — — — (41 ) (41 ) Acquisition and integration costs — — — (7 ) (7 ) Operating income (loss) $ (33 ) $ (104 ) $ 69 $ (49 ) $ (117 ) Earnings from unconsolidated investment — — 4 — 4 Interest expense — — — (166 ) (166 ) Other income and expense, net 3 1 — 25 29 Loss before income taxes (250 ) Income tax benefit — — — 1 1 Net loss (249 ) Less: Net income attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (249 ) Total assets—domestic $ 1,432 $ 746 $ 7,498 $ 3,348 $ 13,024 Investment in unconsolidated affiliate $ — $ — $ 173 $ — $ 173 Capital expenditures $ (8 ) $ (11 ) $ (15 ) $ (1 ) $ (35 ) Segment Data as of and for the Nine Months Ended September 30, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,022 $ 575 $ 1,587 $ — $ 3,184 Intercompany and affiliate revenues (24 ) (1 ) 52 — 27 Total revenues $ 998 $ 574 $ 1,639 $ — $ 3,211 Depreciation expense $ (99 ) $ (21 ) $ (370 ) $ (4 ) $ (494 ) Impairments (700 ) (148 ) (9 ) — (857 ) General and administrative expense — — — (117 ) (117 ) Acquisition and integration costs — 8 — (16 ) (8 ) Operating income (loss) $ (728 ) $ (87 ) $ 279 $ (138 ) $ (674 ) Earnings from unconsolidated investment — — 7 — 7 Interest expense — — — (449 ) (449 ) Other income and expense, net 9 15 12 24 60 Loss before income taxes (1,056 ) Income tax expense — — — (6 ) (6 ) Net loss (1,062 ) Less: Net loss attributable to noncontrolling interest (2 ) Net loss attributable to Dynegy Inc. $ (1,060 ) Total assets—domestic $ 1,432 $ 746 $ 7,498 $ 3,348 $ 13,024 Investment in unconsolidated affiliate $ — $ — $ 173 $ — $ 173 Capital expenditures $ (47 ) $ (32 ) $ (171 ) $ (9 ) $ (259 ) Segment Data as of and for the Three Months Ended September 30, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 410 $ 221 $ 605 $ (4 ) $ 1,232 Intercompany revenues (14 ) — 10 4 — Total revenues $ 396 $ 221 $ 615 $ — $ 1,232 Depreciation expense $ (39 ) $ (8 ) $ (126 ) $ (1 ) $ (174 ) Impairments (74 ) — — — (74 ) General and administrative expense — — — (29 ) (29 ) Acquisition and integration costs — — — (8 ) (8 ) Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107 Losses from unconsolidated investment — — (4 ) — (4 ) Interest expense — — — (145 ) (145 ) Other income and expense, net — — — 46 46 Income before income taxes 4 Income tax expense — — — (28 ) (28 ) Net loss (24 ) Less: Net income attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (24 ) Total assets—domestic $ 2,426 $ 993 $ 7,948 $ 790 $ 12,157 Investment in unconsolidated affiliate $ — $ — $ 189 $ — $ 189 Capital expenditures $ (25 ) $ (12 ) $ (29 ) $ (3 ) $ (69 ) Segment Data as of and for the Nine Months Ended September 30, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 976 $ 629 $ 1,254 $ (5 ) $ 2,854 Intercompany revenues (131 ) (4 ) 130 5 — Total revenues $ 845 $ 625 $ 1,384 $ — $ 2,854 Depreciation expense $ (96 ) $ (24 ) $ (290 ) $ (3 ) $ (413 ) Impairments (74 ) — — — (74 ) General and administrative expense — — — (94 ) (94 ) Acquisition and integration costs — — — (121 ) (121 ) Operating income (loss) $ (34 ) $ 39 $ 290 $ (218 ) $ 77 Losses from unconsolidated investment — — (1 ) — (1 ) Interest expense — — — (413 ) (413 ) Other income and expense, net — — — 45 45 Loss before income taxes (292 ) Income tax benefit — — — 473 473 Net income 181 Less: Net loss attributable to noncontrolling interest (3 ) Net income attributable to Dynegy Inc. $ 184 Total assets—domestic $ 2,426 $ 993 $ 7,948 $ 790 $ 12,157 Investment in unconsolidated affiliate $ — $ — $ 189 $ — $ 189 Capital expenditures $ (44 ) $ (41 ) $ (78 ) $ (8 ) $ (171 )

Subsequent Events

Subsequent Events	9 Months Ended
	Sep. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 21—Subsequent Events Genco Debt Restructure On October 14, 2016, we entered into an RSA with Genco and the Ad Hoc Group to restructure Genco’s Senior Notes either through (a) out-of-court exchanges (the “Exchange Offers”) or (b) if the Exchange Offers are not successful (as discussed below), a pre-packaged plan of reorganization for Genco (the “Plan”). Under the RSA, the $825 million of existing Genco Senior Notes will be exchanged for up to $210 million in new seven-year Dynegy unsecured notes, up to $139 million of cash consideration (including a $9 million RSA payment discussed below) funded with existing IPH cash balances and an expected return of collateral of approximately $61 million , and up to 10 million Dynegy warrants with a seven -year term for an exercise price of $35 per share. If the restructuring is consummated pursuant to the Plan, it is expected that participating non-accredited investors will be entitled to a cash payment in lieu of their pro rata allocation of the notes and warrants described above. Solicitation with respect to the Exchange Offers will occur simultaneously with solicitation of the Plan. Genco will continue making interest payments on the Genco Senior Notes, with payments after September 30, 2016 netted against the proposed cash consideration. Dynegy, Genco, and the Ad Hoc Group agreed that holders of the Genco Senior Notes who entered into the RSA on or before October 21, 2016, will be paid their pro rata share of $9 million in cash upon consummation of a restructuring, with such pro rata share determined as the proportion that the amount of Genco Senior Notes held by each such holder bears to the aggregate amount of Genco Senior Notes held by all holders entitled to receive a share of the $9 million . If holders of 97 percent or more of the aggregate principal amount of Genco Senior Notes participate in the Exchange Offers and the other conditions thereto are satisfied, we intend to consummate the restructuring out of court. If holders of less than 97 percent of the aggregate principal amount of Genco Senior Notes participate in the Exchange Offers, but a majority in number of the holders who have voted on the Plan and who hold at least 66.7 percent in the aggregate amount of Genco Senior Notes held by holders voting on the Plan vote to accept the plan, the parties to the RSA intend to consummate the restructuring through a prepackaged Chapter 11 filing of Genco. As of October 24, 2016, the Ad Hoc Group of Genco bondholders represents approximately 70 percent in amount of the $825 million Genco Senior Notes. 2025 Senior Notes On October 11, 2016, Dynegy issued in a private placement transaction $750 million of 8 percent unsecured senior notes due 2025 (the “2025 Senior Notes”). The 2025 Senior Notes do not provide registration rights but otherwise have terms and provisions similar to the Dynegy Senior Notes.

Accounting Policies (Policies)

Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2016
Accounting Policies [Abstract]
Basis of Presentation	The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by the Generally Accepted Accounting Principles of the United States of America (“GAAP”). The unaudited consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Certain prior period amounts in our unaudited consolidated financial statements have been reclassified to conform to current year presentation. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2015 , filed with the SEC on February 25, 2016, which we refer to as our “Form 10-K.” Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. Our current business operations are focused primarily on the unregulated power generation sector of the energy industry. We report the results of our power generation business as three segments in our unaudited consolidated financial statements: (i) the Coal segment (“Coal”), (ii) the IPH segment (“IPH”), and (iii) the Gas segment (“Gas”). Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 20—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.
Use of Estimates	Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors.
Accounting Standards Adopted During the Current Period	Accounting Standards Adopted During the Current Period Hybrid Financial Instruments. In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-16-Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or Equity. The amendments in this ASU clarify how current GAAP should be interpreted in evaluating the economic characteristics and risks of a host contract in a hybrid financial instrument that is issued in the form of a share. Specifically, the amendments clarify that an entity should consider all relevant terms and features, including the embedded derivative feature being evaluated for bifurcation, in evaluating the nature of the host contract. Furthermore, the amendments clarify that no single term or feature would necessarily determine the economic characteristics and risks of the host contract. Rather, the nature of the host contract depends upon the economic characteristics and risks of the entire hybrid financial instrument. The amendments in this ASU also clarify that, in evaluating the nature of a host contract, an entity should assess the substance of the relevant terms and features (i.e., the relative strength of the debt-like or equity-like terms and features given the facts and circumstances) when considering how to weight those terms and features. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements. Debt Issuance Costs. In April 2015, the FASB issued ASU 2015-03-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU require that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for our debt issuance costs are not affected by the amendments in this update. In August 2015, the FASB issued ASU 2015-15-Interest-Imputation of Interest (Subtopic 835-30). The amendments in this ASU further clarify the guidance provided in ASU 2015-03 to include the presentation of debt issuance costs in relation to line-of-credit arrangements. The amendments state these costs may be presented as an asset and subsequently amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit arrangement. We adopted these ASUs on January 1, 2016, on a retrospective basis affecting presentation on the unaudited consolidated balance sheets for all periods presented. Accordingly, we reclassified unamortized debt issuance costs of $3 million from Prepayments and other current assets to Debt, current portion, net and $77 million from Other long-term assets to Debt, long-term portion, net within our unaudited consolidated balance sheet as of December 31, 2015. 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, a nd (v) consolidation of certain investment funds. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements. Extraordinary and Unusual Items. In January 2015, the FASB issued ASU 2015-01-Income Statement-Extraordinary and Unusual Items (Subtopic 225-20). The amendments in this ASU eliminate from GAAP the concept of extraordinary items and will no longer require separate classification of these items within the statement of operations. Presentation and disclosure guidance for items that are unusual in nature or occur infrequently will be retained and will be expanded to include items that are both unusual in nature and infrequently occurring. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. The adoption of this ASU on January 1, 2016, did not have an impact on our unaudited consolidated financial statements.
Accounting Standards Not Yet Adopted	Accounting Standards Not Yet Adopted Statement of Cash Flows. In August 2016, the FASB issued ASU 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Credit Losses. In June 2016, the FASB issued ASU 2016-13-Financial Instruments-Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The amendments in this ASU require the measurement of all expected credit losses for financial assets, which include trade receivables, held at the reporting date based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted for interim and annual periods beginning after December 15, 2018. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Debt Instruments. In March 2016, the FASB issued ASU 2016-06-Derivative and Hedging: Contingent Put and Call Options in Debt Instruments. The amendments in this ASU clarify what steps are required when assessing whether the economic characteristics and risks of call (put) options are clearly and closely related to the economic characteristics and risks of their debt hosts, which is one of the criteria for bifurcating an embedded derivative. An entity performing the assessment under the amendments in this ASU is required to assess the embedded call (put) options solely in accordance with the four-step decision sequence. The amendments are effective for public business entities for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. All entities have the option of adopting the new requirements early, including adoption in an interim period. If an entity early adopts the new requirements in an interim period, it must reflect any adjustments as of the beginning of the fiscal year that includes that interim period. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. Going Concern. In August 2014, the FASB issued ASU 2014-15-Presentation of Financial Statements-Going Concern (Subtopic 205-40). The amendments in this ASU require management, in connection with preparing financial statements for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued (or within one year after the date that the financial statements are available to be issued, when applicable). Currently, there is no guidance in GAAP about management’s responsibility to evaluate whether there is substantial doubt about an entity’s ability to continue as a going concern or to provide related footnote disclosures. The amendments in this ASU provide that guidance. In doing so, the amendments should reduce diversity in the timing and content of footnote disclosures. The guidance in this ASU is effective for fiscal years ending after December 15, 2016, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB and International Accounting Standards Board jointly issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU, and subsequently issued amendments to the standard, develop a common revenue standard for GAAP and International Financial Reporting Standards 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 and its amendments is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently evaluating this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Acquisitions (Tables)

Acquisitions (Tables)	9 Months Ended
	Sep. 30, 2016
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the consideration paid and the fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 126 175 Inventory 167 105 272 Assets from risk management activities (including current portion of $4 million and $30 million, respectively) 4 33 37 Prepayments and other current assets 32 69 101 Property, plant and equipment 2,773 2,734 5,507 Investment in unconsolidated affiliate 200 — 200 Intangible assets (including current portion of $67 million and $36 million, respectively) 111 84 195 Other long-term assets 28 35 63 Total assets acquired 3,631 3,186 6,817 Accounts payable 27 96 123 Accrued liabilities and other current liabilities 21 10 31 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 509 — 509 Other long-term liabilities — 40 40 Total liabilities assumed 769 395 1,164 Identifiable net assets acquired 2,862 2,791 5,653 Goodwill 799 — 799 Net assets acquired $ 3,661 $ 2,791 $ 6,452
Business Acquisition, Pro Forma Information	The unaudited pro forma financial results for the nine months ended September 30, 2015 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 as of January 1, 2014, nor are they indicative of future results of operations. (amounts in millions) Nine Months Ended September 30, 2015 Revenues $ 3,844 Net income $ 442 Net loss attributable to noncontrolling interests $ (3 ) Net income attributable to Dynegy Inc. $ 445

Risk Management Activities, D31

Risk Management Activities, Derivatives and Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts and Interest Rate Swaps	As of September 30, 2016 , we had net purchases and sales of derivative contracts outstanding in the following quantities: Contract Type Quantity Unit of Measure Fair Value (1) (dollars and quantities in millions) Purchases (Sales) Asset (Liability) Commodity contracts: Electricity derivatives (2) (58 ) MWh $ 25 Electricity basis derivatives (3) (30 ) MWh $ (8 ) Natural gas derivatives (2) 362 MMBtu $ (64 ) Natural gas basis derivatives 64 MMBtu $ (22 ) Coal derivatives (4) — Metric Ton $ (7 ) Emissions derivatives 5 Metric Ton $ (5 ) Interest rate swaps 771 U.S. Dollar $ (40 ) Common stock warrants (5) 16 Warrant $ (2 ) __________________________________________ (1) Includes both asset and liability risk management positions but excludes margin and collateral netting of $73 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 tables present the fair value and balance sheet classification of derivatives in our unaudited consolidated balance sheets as of September 30, 2016 and December 31, 2015 . As of September 30, 2016 and December 31, 2015 , there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets. September 30, 2016 Gross amounts offset in the balance sheet Contract Type Location on Balance Sheet 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 $ 351 $ (238 ) $ — $ 113 Total derivative assets $ 351 $ (238 ) $ — $ 113 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (432 ) $ 238 $ 73 $ (121 ) Interest rate contracts Liabilities from risk management activities (40 ) — — (40 ) Common stock warrants Other long-term liabilities (2 ) — — (2 ) Total derivative liabilities $ (474 ) $ 238 $ 73 $ (163 ) Total derivatives $ (123 ) $ — $ 73 $ (50 ) December 31, 2015 Gross amounts offset in the balance sheet Contract Type Location on Balance Sheet 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 )
Schedule of Derivative Collateral Posted and Location on Balance Sheet	The following table summarizes our cash collateral posted as of September 30, 2016 and December 31, 2015 , within Prepayments and other current assets in our unaudited consolidated balance sheets and the amount applied against short-term risk management activities: Location on Balance Sheet September 30, 2016 December 31, 2015 (amounts in millions) Gross collateral posted with counterparties $ 119 $ 162 Less: Collateral netted against risk management liabilities 73 106 Net collateral within Prepayments and other current assets $ 46 $ 56
Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations	Our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016 and 2015 include the impact of derivative financial instruments as presented below: Derivatives Not Designated as Hedges Location of Gain (Loss) Recognized in Income on Derivatives Three Months Ended September 30, Nine Months Ended 2016 2015 2016 2015 (amounts in millions) Commodity contracts Revenues $ (27 ) $ 48 $ 188 $ 120 Interest rate contracts Interest expense $ 1 $ (9 ) $ (11 ) $ (17 ) Common stock warrants Other income and (expense), net $ 4 $ 45 $ 5 $ 43

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2016
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 September 30, 2016 and December 31, 2015 , and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid: Fair Value as of September 30, 2016 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 248 $ 38 $ 286 Natural gas derivatives — 51 10 61 Emissions derivatives — 3 — 3 Coal derivatives — — 1 1 Total assets from commodity risk management activities $ — $ 302 $ 49 $ 351 Liabilities: . Liabilities from commodity risk management activities: Electricity derivatives $ — $ (221 ) $ (48 ) $ (269 ) Natural gas derivatives — (123 ) (24 ) (147 ) Emissions derivatives — (8 ) — (8 ) Coal derivatives — (8 ) — (8 ) Total liabilities from commodity risk management activities — (360 ) (72 ) (432 ) Liabilities from interest rate contracts — (40 ) — (40 ) Liabilities from outstanding common stock warrants (2 ) — — (2 ) Total liabilities $ (2 ) $ (400 ) $ (72 ) $ (474 ) Fair Value as of December 31, 2015 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 308 $ 40 $ 348 Natural gas derivatives — 40 2 42 Coal derivatives — 10 3 13 Total assets from commodity risk management activities $ — $ 358 $ 45 $ 403 Liabilities: Liabilities from commodity risk management activities: Electricity derivatives $ — $ (267 ) $ (58 ) $ (325 ) Natural gas derivatives — (158 ) (34 ) (192 ) Diesel derivatives — (4 ) — (4 ) Coal derivatives — (35 ) (1 ) (36 ) Total liabilities from commodity risk management activities — (464 ) (93 ) (557 ) Liabilities from interest rate contracts — (42 ) — (42 ) Liabilities from outstanding common stock warrants (7 ) — — (7 ) Total liabilities $ (7 ) $ (506 ) $ (93 ) $ (606 )
Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations	The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of September 30, 2016 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Input Significant Unobservable Input Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (10 ) Million MWh $ (7 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs (26 ) Million MWh $ (3 ) Historical congestion Forward price $0 - $6.00 Natural gas derivatives (1) 78 Million MMBtu $ (14 ) Illiquid location fixed price Forward price $1.05 - $1.35 Coal derivatives (1) — Thousand Tons $ 1 Illiquid location fixed price Forward price $6.10 - $7.45 __________________________________________ (1) Represents forward financial and physical transactions at illiquid pricing locations.
Schedule of Changes in Fair Value of Financial Instruments	The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy: Three Months Ended September 30, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at June 30, 2016 $ (24 ) $ (15 ) $ 1 $ (38 ) Total gains (losses) included in earnings 9 (4 ) 1 6 Settlements (1) 5 5 (1 ) 9 Balance at September 30, 2016 $ (10 ) $ (14 ) $ 1 $ (23 ) Unrealized gains (losses) relating to instruments held as of September 30, 2016 $ 9 $ (4 ) $ 1 $ 6 Nine Months Ended September 30, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2015 $ (18 ) $ (32 ) $ 2 $ (48 ) Total gains included in earnings 4 — — 4 Settlements (1) 4 18 (1 ) 21 Balance at September 30, 2016 $ (10 ) $ (14 ) $ 1 $ (23 ) Unrealized gains relating to instruments held as of September 30, 2016 $ 4 $ — $ — $ 4 Three Months Ended September 30, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at June 30, 2015 $ (54 ) $ (11 ) $ (7 ) $ 4 $ (68 ) Total gains (losses) included in earnings 2 (3 ) — — (1 ) Settlements (1) 3 — 5 (1 ) 7 Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3 $ (62 ) Unrealized gains (losses) relating to instruments held as of September 30, 2015 $ 2 $ (3 ) $ — $ — $ (1 ) Nine Months Ended September 30, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Heat Rate Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ — $ (4 ) Acquisitions (54 ) (14 ) (9 ) 5 (72 ) Total gains included in earnings 7 — — — 7 Settlements (1) 2 — 7 (2 ) 7 Balance at September 30, 2015 $ (49 ) $ (14 ) $ (2 ) $ 3 $ (62 ) Unrealized gains relating to instruments held as of September 30, 2015 $ 7 $ — $ — $ — $ 7 _________________________________________ (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 Financial Assets and Liabilities	Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of September 30, 2016 and December 31, 2015 , respectively. September 30, 2016 December 31, 2015 (amounts in millions) Fair Value Hierarchy Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (1) Level 2 $ (2,081 ) $ (2,168 ) $ (2,077 ) $ (1,985 ) Tranche B-2 Term Loan, due 2020 (1) Level 2 $ (762 ) $ (779 ) $ (766 ) $ (754 ) 7.375% Senior Notes, due 2022 (1) Level 2 $ (1,731 ) $ (1,724 ) $ (1,729 ) $ (1,531 ) 5.875% Senior Notes, due 2023 (1) Level 2 $ (492 ) $ (450 ) $ (491 ) $ (404 ) 7.625% Senior Notes, due 2024 (1) Level 2 $ (1,236 ) $ (1,225 ) $ (1,235 ) $ (1,078 ) 7.00% Amortizing Notes, due 2019 (TEUs) (1) Level 2 $ (84 ) $ (88 ) $ — $ — Forward capacity agreement (1) Level 3 $ (203 ) $ (203 ) $ — $ — Inventory financing agreements Level 3 $ (136 ) $ (135 ) $ (136 ) $ (137 ) Equipment financing agreements (1) Level 3 $ (75 ) $ (75 ) $ (61 ) $ (61 ) Interest rate derivatives Level 2 $ (40 ) $ (40 ) $ (42 ) $ (42 ) Commodity-based derivative contracts (2) Various $ (81 ) $ (81 ) $ (154 ) $ (154 ) Common stock warrants Level 1 $ (2 ) $ (2 ) $ (7 ) $ (7 ) Dynegy Finance IV, Inc.: Tranche C Term Loan, due 2023 (1) Level 2 $ (1,995 ) $ (2,015 ) $ — $ — Genco: 7.00% Senior Notes Series H, due 2018 (1) Level 2 $ (284 ) $ (119 ) $ (276 ) $ (204 ) 6.30% Senior Notes Series I, due 2020 (1) Level 2 $ (218 ) $ (99 ) $ (213 ) $ (148 ) 7.95% Senior Notes Series F, due 2032 (1) Level 2 $ (226 ) $ (107 ) $ (225 ) $ (162 ) __________________________________________ (1) Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion. (2) Carrying amounts exclude $73 million and $106 million of cash posted as collateral, as of September 30, 2016 and December 31, 2015 , respectively.

Accumulated Other Comprehensi33

Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2016
Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Changes in accumulated other comprehensive income, net of tax, by component, are as follows: Nine Months Ended September 30, (amounts in millions) 2016 2015 Beginning of period $ 19 $ 20 Other comprehensive income (loss) before reclassifications: Actuarial gain and plan amendments (net of tax of zero and $2, respectively) — 7 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively) (1) (4 ) (3 ) Net current period other comprehensive income (loss), net of tax (4 ) 4 End of period $ 15 $ 24 __________________________________________ (1) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 16—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory (Tables)

Inventory (Tables)	9 Months Ended
	Sep. 30, 2016
Inventory Disclosure [Abstract]
Summary of Inventories	A summary of our inventories is as follows: (amounts in millions) September 30, 2016 December 31, 2015 Materials and supplies $ 183 $ 178 Coal (1) 233 350 Fuel oil (1) 17 17 Emissions allowances (2) 14 51 Other — 1 Total $ 447 $ 597 __________________________________________ (1) At September 30, 2016 , approximately $47 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 13—Debt — Brayton Point Inventory Financing for further discussion. (2) At September 30, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt — Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	9 Months Ended
	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of our property, plant and equipment is as follows: (amounts in millions) September 30, 2016 December 31, 2015 Power generation $ 7,481 $ 8,178 Buildings and improvements 938 956 Office and other equipment 103 101 Property, plant and equipment 8,522 9,235 Accumulated depreciation (1,270 ) (888 ) Property, plant and equipment, net $ 7,252 $ 8,347

Joint Ownership of Generating36

Joint Ownership of Generating Facilities (Tables)	9 Months Ended
	Sep. 30, 2016
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	The following tables present the ownership interests of the jointly owned facilities as of September 30, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. September 30, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 206 $ (33 ) $ 3 $ 176 Stuart (1) 39.0 % $ — $ — $ — $ — Conesville (1) 40.0 % $ 61 $ (2 ) $ 5 $ 64 Zimmer 46.5 % $ 116 $ (21 ) $ 4 $ 99 Killen (1) 33.0 % $ 18 $ (1 ) $ 2 $ 19 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 Liabili37

Intangible Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2016
Intangible Assets, Net (Excluding Goodwill) [Abstract]
Intangible Assets and Liabilities	The following table summarizes the components of our intangible assets and liabilities as of September 30, 2016 and December 31, 2015 : September 30, 2016 December 31, 2015 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (187 ) $ 73 $ 260 $ (126 ) $ 134 Gas transport contracts 46 (37 ) 9 46 (16 ) 30 Total intangible assets $ 306 $ (224 ) $ 82 $ 306 $ (142 ) $ 164 Intangible Liabilities: Electricity contracts $ (28 ) $ 26 $ (2 ) $ (30 ) $ 19 $ (11 ) Coal contracts (93 ) 76 (17 ) (134 ) 82 (52 ) Coal transport contracts (104 ) 85 (19 ) (104 ) 64 (40 ) Gas transport contracts (41 ) 7 (34 ) (64 ) 27 (37 ) Total intangible liabilities $ (266 ) $ 194 $ (72 ) $ (332 ) $ 192 $ (140 ) Intangible assets and liabilities, net $ 40 $ (30 ) $ 10 $ (26 ) $ 50 $ 24 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three and nine months ended September 30, 2016 and 2015 : Three Months Ended September 30, Nine Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Electricity contracts, net (1) $ 19 $ 21 $ 52 $ 53 Coal contracts, net (2) (9 ) (19 ) (32 ) (42 ) Coal transport contracts, net (2) (7 ) (9 ) (21 ) (24 ) Gas transport contracts, net (2) 1 (2 ) 18 (5 ) Total $ 4 $ (9 ) $ 17 $ (18 ) __________________________________________ (1) The amortization of these contracts is recognized in Revenues in our unaudited consolidated statements of operations. (2) The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Tangible Equity Units (Tables)

Tangible Equity Units (Tables)	9 Months Ended
	Sep. 30, 2016
Equity [Abstract]
Schedule of Tangible Equity Units	We allocated the proceeds from the issuance of the TEUs, including other fees and expenses, to equity and debt based on the relative fair value of the respective components of each TEU as follows: (in millions, except price per TEU) SPC Amortizing Note Total Price per TEU $ 81 $ 19 $ 100 Gross proceeds $ 373 $ 87 $ 460 Less: Issuance costs (14 ) (3 ) (17 ) Net proceeds $ 359 $ 84 $ 443 Unless settled early at the holder’s or Dynegy’s election or redeemed by Dynegy in connection with an acquisition termination redemption, on July 1, 2019, Dynegy will deliver to the SPC holders a number of shares of common stock based on the 20 day volume-weighted average price (“VWAP”) of our common stock as follows: VWAP of Dynegy Common Stock Common Shares Issued Equal to or greater than $19.92 5.0201 shares (minimum settlement rate) Less than $19.92, but greater than $16.13 $100 divided by VWAP Less than or equal to $16.13 6.1996 shares (maximum settlement rate)

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	A summary of our long-term debt is as follows: (amounts in millions) September 30, 2016 December 31, 2015 Secured Obligations: Dynegy Inc.: Tranche B-2 Term Loan, due 2020 $ 774 $ 780 Revolving Facility — — Forward Capacity Agreement 219 — Inventory Financing Agreements 136 136 Dynegy Finance IV, Inc.: Tranche C Term Loan, due 2023 (1) 2,000 — Subtotal secured obligations 3,129 916 Unsecured Obligations: Dynegy Inc.: 7.00% Amortizing Notes, due 2019 (TEUs) 87 — 6.75% Senior Notes, due 2019 2,100 2,100 7.375% Senior Notes, due 2022 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 1,250 1,250 Equipment Financing Agreements 100 75 Subtotal unsecured obligations 5,787 5,675 Total Dynegy Inc. and Dynegy Finance IV, Inc. 8,916 6,591 Genco Unsecured Obligations: 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 Total Genco (2) 825 825 Total debt obligations 9,741 7,416 Unamortized debt discounts and issuance costs (3) (218 ) (207 ) 9,523 7,209 Less: Current maturities, including unamortized debt discounts and issuance costs, net 167 80 Total Long-term debt $ 9,356 $ 7,129 __________________________________________ (1) At September 30, 2016 , the Tranche C Term Loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our unaudited consolidated balance sheet. Upon the closing of the Delta Transaction, this debt obligation will become Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion. (2) On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes. See Note 21—Subsequent Events —Genco Debt Restructure for further discussion. (3) Includes $97 million and $111 million of unamortized debt discounts as of September 30, 2016 and December 31, 2015 , respectively, relating to the Genco unsecured obligations.
Credit Agreement 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 a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. (2) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from external, third-party sources are included in the definition of indebtedness and are subject to these incurrence tests.

Pension and Other Post-Employ40

Pension and Other Post-Employment Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2016
Compensation and Retirement Disclosure [Abstract]
Schedule of Net Benefit Costs	The components of net periodic benefit cost (gain) were as follows: Pension Benefits Other Benefits Three Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 4 $ 4 $ — $ 1 Interest cost on projected benefit obligation 5 4 1 1 Expected return on plan assets (5 ) (6 ) (1 ) (1 ) Amortization of prior service credit (1 ) — (1 ) (1 ) Net periodic benefit cost (gain) $ 3 $ 2 $ (1 ) $ — Pension Benefits Other Benefits Nine Months Ended September 30, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 12 $ 11 $ — $ 1 Interest cost on projected benefit obligation 15 13 3 3 Expected return on plan assets (17 ) (17 ) (3 ) (3 ) Amortization of prior service credit (1 ) (1 ) (3 ) (2 ) Net periodic benefit cost (gain) $ 9 $ 6 $ (3 ) $ (1 )

Earnings (Loss) Per Share (Tabl

Earnings (Loss) Per Share (Tables)	9 Months Ended
	Sep. 30, 2016
Earnings Per Share [Abstract]
Schedule of Earnings (Loss) Per Share, Basic and Diluted	The basic and diluted earnings (loss) per share from continuing operations attributable to our common stockholders during the three and nine months ended September 30, 2016 and 2015 is shown in the following table: Three Months Ended September 30, Nine Months Ended September 30, (in millions, except per share amounts) 2016 2015 2016 2015 Income (loss) from continuing operations $ (249 ) $ (24 ) $ (1,062 ) $ 181 Less: Net loss attributable to noncontrolling interest — — (2 ) (3 ) Income (loss) from continuing operations attributable to Dynegy Inc. (249 ) (24 ) (1,060 ) 184 Less: Dividends on preferred stock 5 5 16 16 Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic earnings (loss) per share (254 ) (29 ) (1,076 ) 168 Add: Dividends on preferred stock (1) — — — 16 Adjusted income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for diluted earnings (loss) per share $ (254 ) $ (29 ) $ (1,076 ) $ 184 Basic weighted-average shares (2) 140 126 126 126 Effect of dilutive securities (3) — — — 14 Diluted weighted-average shares 140 126 126 140 Earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders: Basic (2) $ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.33 Diluted (3) $ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.31 __________________________________________ (1) Excluded for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015 due to a net loss from continuing operations for the respective periods. (2) For the three and nine months ended September 30, 2016 , the TEUs are assumed to be outstanding at the minimum settlement amount, or 23,092,460 shares, for weighted-average shares for basic earnings (loss) per share. Please read Note 12—Tangible Equity Units for further discussion. (3) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015 .
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	For the three and nine months ended September 30, 2016 and 2015 , the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive: Three Months Ended September 30, Nine Months Ended September 30, (in millions of shares) 2016 2015 2016 2015 Stock options 2.8 1.8 2.8 — Restricted stock units 1.3 1.5 1.3 — Performance stock units 1.2 0.6 1.2 — Warrants 15.6 15.6 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 12.9 12.9 — Prepaid stock purchase contract (TEUs) 5.4 — 5.4 — Total 39.2 32.4 39.2 15.6

Condensed Consolidating Finan42

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	Condensed Consolidating Balance Sheet as of September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 1,248 $ 69 $ 141 $ — $ 1,458 Restricted cash — — 85 — 85 Accounts receivable, net 115 2,383 135 (2,259 ) 374 Inventory — 234 213 — 447 Other current assets 11 235 31 (2 ) 275 Total Current Assets 1,374 2,921 605 (2,261 ) 2,639 Property, plant and equipment, net — 6,901 351 — 7,252 Investment in affiliates 12,335 173 — (12,335 ) 173 Restricted cash — — 2,000 — 2,000 Goodwill — 799 — — 799 Other long-term assets 4 112 45 — 161 Intercompany note receivable — — 3 (3 ) — Total Assets $ 13,713 $ 10,906 $ 3,004 $ (14,599 ) $ 13,024 Current Liabilities Accounts payable $ 1,745 $ 226 $ 551 $ (2,259 ) $ 263 Other current liabilities 224 293 133 (2 ) 648 Total Current Liabilities 1,969 519 684 (2,261 ) 911 Debt, long-term portion, net 6,355 288 2,713 — 9,356 Intercompany note payable 3,042 — — (3,042 ) — Other long-term liabilities 136 287 130 (3 ) 550 Total Liabilities 11,502 1,094 3,527 (5,306 ) 10,817 Stockholders’ Equity Dynegy Stockholders’ Equity 2,211 12,854 (519 ) (12,335 ) 2,211 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,211 9,812 (519 ) (9,293 ) 2,211 Noncontrolling interest — — (4 ) — (4 ) Total Equity 2,211 9,812 (523 ) (9,293 ) 2,207 Total Liabilities and Equity $ 13,713 $ 10,906 $ 3,004 $ (14,599 ) $ 13,024 Condensed Consolidating Balance Sheet as of 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 13 335 55 (14 ) 389 Total Current Assets 839 2,263 574 (1,744 ) 1,932 Property, plant and equipment, net — 7,813 534 — 8,347 Investment in affiliates 13,017 190 — (13,017 ) 190 Other long-term assets 10 133 50 — 193 Goodwill — 797 — — 797 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459 Current Liabilities Accounts payable $ 1,388 $ 238 $ 396 $ (1,730 ) $ 292 Other current liabilities 92 277 162 (14 ) 517 Total Current Liabilities 1,480 515 558 (1,744 ) 809 Debt, long-term portion, net 6,293 122 714 — 7,129 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 10,962 954 1,427 (4,803 ) 8,540 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459
Condensed Consolidating Statements of Operations	Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 919 $ 267 $ (2 ) $ 1,184 Cost of sales, excluding depreciation expense — (501 ) (161 ) 2 (660 ) Gross margin — 418 106 — 524 Operating and maintenance expense — (152 ) (66 ) — (218 ) Depreciation expense — (147 ) (16 ) — (163 ) Impairments — (64 ) (148 ) — (212 ) General and administrative expense (2 ) (28 ) (11 ) — (41 ) Acquisition and integration costs (5 ) — (2 ) — (7 ) Other — (1 ) 1 — — Operating income (loss) (7 ) 26 (136 ) — (117 ) Earnings from unconsolidated investment — 4 — — 4 Equity in losses from investments in affiliates (153 ) — — 153 — Interest expense (112 ) (5 ) (50 ) 1 (166 ) Other income and expense, net 23 5 2 (1 ) 29 Income (loss) before income taxes (249 ) 30 (184 ) 153 (250 ) Income tax benefit (expense) — 37 (36 ) — 1 Net income (loss) (249 ) 67 (220 ) 153 (249 ) Less: Net loss attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (249 ) $ 67 $ (220 ) $ 153 $ (249 ) Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,517 $ 696 $ (2 ) $ 3,211 Cost of sales, excluding depreciation expense — (1,295 ) (405 ) 2 (1,698 ) Gross margin — 1,222 291 — 1,513 Operating and maintenance expense — (503 ) (192 ) — (695 ) Depreciation expense — (433 ) (61 ) — (494 ) Impairments — (709 ) (148 ) — (857 ) General and administrative expense (5 ) (87 ) (25 ) — (117 ) Acquisition and integration costs (8 ) (3 ) 3 — (8 ) Other — (1 ) (15 ) — (16 ) Operating loss (13 ) (514 ) (147 ) — (674 ) Earnings from unconsolidated investment — 7 — — 7 Equity in losses from investments in affiliates (718 ) — — 718 — Interest expense (355 ) (9 ) (87 ) 2 (449 ) Other income and expense, net 26 20 16 (2 ) 60 Loss before income taxes (1,060 ) (496 ) (218 ) 718 (1,056 ) Income tax benefit (expense) — 30 (36 ) — (6 ) Net loss (1,060 ) (466 ) (254 ) 718 (1,062 ) Less: Net loss attributable to noncontrolling interest — — (2 ) — (2 ) Net loss attributable to Dynegy Inc. $ (1,060 ) $ (466 ) $ (252 ) $ 718 $ (1,060 ) Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 878 $ 249 $ 105 $ 1,232 Cost of sales, excluding depreciation expense — (369 ) (147 ) (105 ) (621 ) Gross margin — 509 102 — 611 Operating and maintenance expense — (154 ) (65 ) — (219 ) Depreciation expense — (149 ) (25 ) — (174 ) Impairments — (74 ) — — (74 ) General and administrative expense 3 (26 ) (6 ) — (29 ) Acquisition and integration costs — (8 ) — — (8 ) Operating income 3 98 6 — 107 Losses from unconsolidated investment — (4 ) — — (4 ) Equity in earnings from investments in affiliates 53 — — (53 ) — Interest expense (127 ) — (18 ) — (145 ) Other income and expense, net 47 (1 ) — — 46 Income (loss) before income taxes (24 ) 93 (12 ) (53 ) 4 Income tax benefit (expense) — (45 ) 17 — (28 ) Net income (loss) (24 ) 48 5 (53 ) (24 ) Less: Net loss attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (24 ) $ 48 $ 5 $ (53 ) $ (24 ) Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 2,186 $ 672 $ (4 ) $ 2,854 Cost of sales, excluding depreciation expense — (1,080 ) (418 ) 4 (1,494 ) Gross margin — 1,106 254 — 1,360 Operating and maintenance expense — (385 ) (195 ) — (580 ) Depreciation expense — (352 ) (61 ) — (413 ) Impairments — (74 ) — — (74 ) General and administrative expense — (69 ) (25 ) — (94 ) Acquisition and integration costs — (121 ) — — (121 ) Other — (1 ) — — (1 ) Operating income (loss) — 104 (27 ) — 77 Losses from unconsolidated investment — (1 ) — — (1 ) Equity in earnings from investments in affiliates 500 — — (500 ) — Interest expense (361 ) — (52 ) — (413 ) Other income and expense, net 45 — — — 45 Income (loss) before income taxes 184 103 (79 ) (500 ) (292 ) Income tax benefit — 473 — — 473 Net income (loss) 184 576 (79 ) (500 ) 181 Less: Net loss attributable to noncontrolling interest — — (3 ) — (3 ) Net income (loss) attributable to Dynegy Inc. $ 184 $ 576 $ (76 ) $ (500 ) $ 184
Condensed Consolidating Statements of Comprehensive Income (Loss)	Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (249 ) $ 67 $ (220 ) $ 153 $ (249 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (1 ) — (1 ) — (2 ) Other comprehensive loss from investment in affiliates (1 ) — — 1 — Other comprehensive loss, net of tax (2 ) — (1 ) 1 (2 ) Comprehensive income (loss) (251 ) 67 (221 ) 154 (251 ) Less: Comprehensive income (loss) attributable to noncontrolling interest — — — — — Total comprehensive income (loss) attributable to Dynegy Inc. $ (251 ) $ 67 $ (221 ) $ 154 $ (251 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net loss $ (1,060 ) $ (466 ) $ (254 ) $ 718 $ (1,062 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit, net of tax of zero (3 ) — (1 ) — (4 ) Other comprehensive loss from investment in affiliates (1 ) — — 1 — Other comprehensive loss, net of tax (4 ) — (1 ) 1 (4 ) Comprehensive loss (1,064 ) (466 ) (255 ) 719 (1,066 ) Less: Comprehensive loss attributable to noncontrolling interest — — (2 ) — (2 ) Total comprehensive loss attributable to Dynegy Inc. $ (1,064 ) $ (466 ) $ (253 ) $ 719 $ (1,064 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (24 ) $ 48 $ 5 $ (53 ) $ (24 ) Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of tax of $2 6 — 7 — 13 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — (1 ) Other comprehensive income from investment in affiliates 7 — — (7 ) — Other comprehensive income, net of tax 12 — 7 (7 ) 12 Comprehensive income (loss) (12 ) 48 12 (60 ) (12 ) Less: Comprehensive income attributable to noncontrolling interest 1 — 1 (1 ) 1 Total comprehensive income (loss) attributable to Dynegy Inc. $ (13 ) $ 48 $ 11 $ (59 ) $ (13 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ 184 $ 576 $ (79 ) $ (500 ) $ 181 Other comprehensive income before reclassifications: Actuarial gain and plan amendments, net of tax of $2 1 — 7 — 8 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (3 ) — — — (3 ) Other comprehensive income from investment in affiliates 7 — — (7 ) — Other comprehensive income, net of tax 5 — 7 (7 ) 5 Comprehensive income (loss) 189 576 (72 ) (507 ) 186 Less: Comprehensive income (loss) attributable to noncontrolling interest 1 — (2 ) (1 ) (2 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ 188 $ 576 $ (70 ) $ (506 ) $ 188
Condensed Consolidating Statements of Cash Flow	Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (155 ) $ 780 $ 24 $ — $ 649 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — (227 ) (32 ) — (259 ) Increase in restricted cash — — (2,045 ) — (2,045 ) Net intercompany transfers 670 — — (670 ) — Distributions from unconsolidated affiliate — 14 — — 14 Other investing — 10 — — 10 Net cash provided by (used in) investing activities 670 (203 ) (2,077 ) (670 ) (2,280 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs 84 198 1,995 — 2,277 Repayments of borrowings (6 ) (15 ) — — (21 ) Proceeds from issuance of equity, net of issuance costs 359 — — — 359 Preferred stock dividends paid (16 ) — — — (16 ) Interest rate swap settlement payments (13 ) — — — (13 ) Net intercompany transfers — (785 ) 115 670 — Other financing (2 ) — — — (2 ) Net cash provided by (used in) financing activities 406 (602 ) 2,110 670 2,584 Net increase (decrease) in cash and cash equivalents 921 (25 ) 57 — 953 Cash and cash equivalents, beginning of period 327 94 84 — 505 Cash and cash equivalents, end of period $ 1,248 $ 69 $ 141 $ — $ 1,458 Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2015 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (141 ) $ 502 $ (59 ) $ — $ 302 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (8 ) (122 ) (41 ) — (171 ) Acquisition, net of cash acquired (6,207 ) 29 100 — (6,078 ) Decrease in restricted cash 5,148 — — — 5,148 Net intercompany transfers 349 — — (349 ) — Distributions from unconsolidated affiliate — 8 — — 8 Other investing — (6 ) — — (6 ) Net cash provided by (used in) investing activities (718 ) (91 ) 59 (349 ) (1,099 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from long-term borrowings, net of debt issuance costs (31 ) 78 10 — 57 Repayments of borrowings (6 ) (23 ) — — (29 ) Proceeds from issuance of equity, net of issuance costs (6 ) — — — (6 ) Preferred stock dividends paid (17 ) — — — (17 ) Interest rate swap settlement payments (13 ) — — — (13 ) Net intercompany transfers — (344 ) (5 ) 349 — Repurchase of common stock (127 ) — — — (127 ) Other financing (4 ) — — — (4 ) Net cash provided by (used in) financing activities (204 ) (289 ) 5 349 (139 ) Net increase (decrease) in cash and cash equivalents (1,063 ) 122 5 — (936 ) Cash and cash equivalents, beginning of period 1,642 54 174 — 1,870 Cash and cash equivalents, end of period $ 579 $ 176 $ 179 $ — $ 934

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2016
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2016 and 2015 is presented below: Segment Data as of and for the Three Months Ended September 30, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 388 $ 241 $ 539 $ — $ 1,168 Intercompany and affiliate revenues — 1 15 — 16 Total revenues $ 388 $ 242 $ 554 $ — $ 1,184 Depreciation expense $ (27 ) $ (7 ) $ (128 ) $ (1 ) $ (163 ) Impairments (55 ) (148 ) (9 ) — (212 ) General and administrative expense — — — (41 ) (41 ) Acquisition and integration costs — — — (7 ) (7 ) Operating income (loss) $ (33 ) $ (104 ) $ 69 $ (49 ) $ (117 ) Earnings from unconsolidated investment — — 4 — 4 Interest expense — — — (166 ) (166 ) Other income and expense, net 3 1 — 25 29 Loss before income taxes (250 ) Income tax benefit — — — 1 1 Net loss (249 ) Less: Net income attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (249 ) Total assets—domestic $ 1,432 $ 746 $ 7,498 $ 3,348 $ 13,024 Investment in unconsolidated affiliate $ — $ — $ 173 $ — $ 173 Capital expenditures $ (8 ) $ (11 ) $ (15 ) $ (1 ) $ (35 ) Segment Data as of and for the Nine Months Ended September 30, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 1,022 $ 575 $ 1,587 $ — $ 3,184 Intercompany and affiliate revenues (24 ) (1 ) 52 — 27 Total revenues $ 998 $ 574 $ 1,639 $ — $ 3,211 Depreciation expense $ (99 ) $ (21 ) $ (370 ) $ (4 ) $ (494 ) Impairments (700 ) (148 ) (9 ) — (857 ) General and administrative expense — — — (117 ) (117 ) Acquisition and integration costs — 8 — (16 ) (8 ) Operating income (loss) $ (728 ) $ (87 ) $ 279 $ (138 ) $ (674 ) Earnings from unconsolidated investment — — 7 — 7 Interest expense — — — (449 ) (449 ) Other income and expense, net 9 15 12 24 60 Loss before income taxes (1,056 ) Income tax expense — — — (6 ) (6 ) Net loss (1,062 ) Less: Net loss attributable to noncontrolling interest (2 ) Net loss attributable to Dynegy Inc. $ (1,060 ) Total assets—domestic $ 1,432 $ 746 $ 7,498 $ 3,348 $ 13,024 Investment in unconsolidated affiliate $ — $ — $ 173 $ — $ 173 Capital expenditures $ (47 ) $ (32 ) $ (171 ) $ (9 ) $ (259 ) Segment Data as of and for the Three Months Ended September 30, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 410 $ 221 $ 605 $ (4 ) $ 1,232 Intercompany revenues (14 ) — 10 4 — Total revenues $ 396 $ 221 $ 615 $ — $ 1,232 Depreciation expense $ (39 ) $ (8 ) $ (126 ) $ (1 ) $ (174 ) Impairments (74 ) — — — (74 ) General and administrative expense — — — (29 ) (29 ) Acquisition and integration costs — — — (8 ) (8 ) Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107 Losses from unconsolidated investment — — (4 ) — (4 ) Interest expense — — — (145 ) (145 ) Other income and expense, net — — — 46 46 Income before income taxes 4 Income tax expense — — — (28 ) (28 ) Net loss (24 ) Less: Net income attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (24 ) Total assets—domestic $ 2,426 $ 993 $ 7,948 $ 790 $ 12,157 Investment in unconsolidated affiliate $ — $ — $ 189 $ — $ 189 Capital expenditures $ (25 ) $ (12 ) $ (29 ) $ (3 ) $ (69 ) Segment Data as of and for the Nine Months Ended September 30, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 976 $ 629 $ 1,254 $ (5 ) $ 2,854 Intercompany revenues (131 ) (4 ) 130 5 — Total revenues $ 845 $ 625 $ 1,384 $ — $ 2,854 Depreciation expense $ (96 ) $ (24 ) $ (290 ) $ (3 ) $ (413 ) Impairments (74 ) — — — (74 ) General and administrative expense — — — (94 ) (94 ) Acquisition and integration costs — — — (121 ) (121 ) Operating income (loss) $ (34 ) $ 39 $ 290 $ (218 ) $ 77 Losses from unconsolidated investment — — (1 ) — (1 ) Interest expense — — — (413 ) (413 ) Other income and expense, net — — — 45 45 Loss before income taxes (292 ) Income tax benefit — — — 473 473 Net income 181 Less: Net loss attributable to noncontrolling interest (3 ) Net income attributable to Dynegy Inc. $ 184 Total assets—domestic $ 2,426 $ 993 $ 7,948 $ 790 $ 12,157 Investment in unconsolidated affiliate $ — $ — $ 189 $ — $ 189 Capital expenditures $ (44 ) $ (41 ) $ (78 ) $ (8 ) $ (171 )

Basis of Presentation and Org44

Basis of Presentation and Organization (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)segment	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Number of reportable segments | segment	3
Carrying amount	$ 9,741	$ 7,416
Genco
Debt Instrument [Line Items]
Carrying amount	$ 825

Accounting Policies (Details)

Accounting Policies (Details) - Accounting Standards Update 2015-03 $ in Millions	Dec. 31, 2015USD ($)
Prepayments and Other Current Assets
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred finance costs, net	$ 3
Other long-term assets
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred finance costs, net	77
Debt, current portion, net
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred finance costs, net	(3)
Debt, long-term portion
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Deferred finance costs, net	$ (77)

Acquisitions (Delta Stock Purch

Acquisitions (Delta Stock Purchase Agreement) (Details)		Dec. 31, 2016USD ($)	Feb. 24, 2016USD ($)facilityPositionMWshares	Sep. 30, 2016USD ($)	Jun. 30, 2016USD ($)shares	Sep. 30, 2016USD ($)	Jun. 27, 2016USD ($)	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Cash					$ 6,150,000,000
Carrying amount				$ 9,741,000,000		$ 9,741,000,000		$ 7,416,000,000
Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Capacity of power facilities acquired | MW			9,058
Natural gas power facilities acquired | facility			15
Cash			$ 3,300,000,000
Purchase agreement termination rights, closing period			12 months
Delta Stock Purchase Agreement | Dynegy, Inc.
Business Acquisition [Line Items]
Ownership interest, percentage							100.00%
Delta Stock Purchase Agreement | Energy Capital Partners
Business Acquisition [Line Items]
Ownership interest, percentage			35.00%
PIPE Stock Purchase Agreement | Dynegy, Inc.
Business Acquisition [Line Items]
Number of Board of Directors positions | Position			1
Guarantee Obligations | Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Number of claims and amount of accrued indemnifications, if any							$ 132,000,000
Common Stock [Member] | PIPE Stock Purchase Agreement | Dynegy, Inc.
Business Acquisition [Line Items]
Stock issued during the period, shares, acquisitions | shares			13,711,152
Stock issued during the period, value			$ 150,000,000
Investor Rights Agreement, Minimum stock ownership percentage			10.00%
Minimum | Forecasted
Business Acquisition [Line Items]
Cash		$ 375,000,000
Maximum | Forecasted
Business Acquisition [Line Items]
Cash		$ 468,500,000
Tangible Equity Units
Business Acquisition [Line Items]
Number of units issued | shares					4,600,000
Proceeds TEUs					$ 446,000,000	443,000,000
Issuance costs of TEUs				3,000,000	$ 14,000,000	17,000,000
Tranche C Term Loan, due 2023
Business Acquisition [Line Items]
Maximum borrowing capacity				2,000,000,000		2,000,000,000
Revolving Credit Facility, Tranche B
Business Acquisition [Line Items]
Line of credit facility, amount outstanding							$ 75,000,000
Secured Debt
Business Acquisition [Line Items]
Carrying amount				3,129,000,000		3,129,000,000		916,000,000
Secured Debt | Tranche C Term Loan, due 2023 | Dynegy Finance IV, Inc.
Business Acquisition [Line Items]
Carrying amount	[1]			$ 2,000,000,000		$ 2,000,000,000		$ 0
Debt instrument term						7 years
TEXAS | Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Coal-Fired power facilities | facility			1
PENNSYLVANIA | Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Coal-Fired power facilities | facility			1
[1]	At September 30, 2016, the Tranche C Term Loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our unaudited consolidated balance sheet. Upon the closing of the Delta Transaction, this debt obligation will become Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion.

Acquisitions (ECP Purchase Agre

Acquisitions (ECP Purchase Agreements) (Details) $ in Millions	Apr. 01, 2015USD ($)facilityMW	Jun. 30, 2016USD ($)
Business Acquisition [Line Items]
Cash | $		$ 6,150
Equity interests issued and issuable | $		$ 105
ERC Purchase Agreement
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)	100.00%
Combined cycle gas facilities acquired	5
Natural gas power facilities acquired	1
Coal-Fired power facilities	1
EquiPower Resources Corp. and Brayton Point Holdings, LLC | Brayton Point Holdings, LLC
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)	100.00%
EquiPower Acquisition
Business Acquisition [Line Items]
Natural gas power facilities acquired	6
Gas and oil power facilities acquired	2
Coal-Fired power facilities	2
Capacity of power facilities acquired | MW	6,300
Cash | $	$ 3,350
Equity interests issued and issuable | $	$ 105

Acquisitions (Duke Midwest Purc

Acquisitions (Duke Midwest Purchase Agreement) (Details) $ in Millions	Apr. 02, 2015USD ($)facilityAffiliateMW	Jun. 30, 2016USD ($)
Business Acquisition [Line Items]
Cash | $		$ 6,150
Duke Midwest Purchase Agreement
Business Acquisition [Line Items]
Retail Energy Business acquired	1
Percent of voting interests acquired (as a percentage)	100.00%
Number of affiliates | Affiliate	2
Capacity of power facilities acquired | MW	6,200
Combined cycle gas facilities acquired	3
Natural gas power facilities acquired	2
Cash | $	$ 2,800
Duke Midwest Purchase Agreement | Gas
Business Acquisition [Line Items]
Natural gas power facilities acquired	5
Duke Midwest Purchase Agreement | Coal
Business Acquisition [Line Items]
Oil-Fired power facilities	1
Coal-Fired power facilities	5
Duke Midwest Purchase Agreement | Parent | Coal
Business Acquisition [Line Items]
Coal-Fired power facilities	2
Duke Midwest Purchase Agreement | Third Parties | Coal
Business Acquisition [Line Items]
Coal-Fired power facilities	3

Acquisitions (Business Combinat

Acquisitions (Business Combination Accounting) (Details) - EquiPower and Duke Midwest Acquisitions - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended	60 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2025	Dec. 31, 2019
Business Acquisition [Line Items]
Acquisition and integration costs	$ 0	$ 1,000,000	$ 0	$ 86,000,000
Revenues and gains recognized	543,000,000	626,000,000	1,675,000,000	1,128,000,000
Operating gains (losses)	$ (34,000,000)	$ 120,000,000	$ 146,000,000	$ 190,000,000
Forecasted
Business Acquisition [Line Items]
Long-term growth rate (as a percentage)					2.50%
Operations, maintenance and capital expenditures, growth rate after year five (as a percentage)						2.50%
Minimum | Gas
Business Acquisition [Line Items]
Discount rate (as a percentage)			8.00%
Minimum | Coal
Business Acquisition [Line Items]
Discount rate (as a percentage)			9.00%
Maximum | Gas
Business Acquisition [Line Items]
Discount rate (as a percentage)			10.00%
Maximum | Coal
Business Acquisition [Line Items]
Discount rate (as a percentage)			13.00%

Acquisitions (Schedule of Asset

Acquisitions (Schedule of Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Millions	Apr. 02, 2015	Apr. 01, 2015	Jun. 30, 2016	Sep. 30, 2016	Dec. 31, 2015
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
Cash			267
Accounts receivable			175
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			6,817
Accounts payable			123
Accrued liabilities and other current liabilities			31
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			509
Other long-term liabilities			40
Total liabilities assumed			1,164
Identifiable net assets acquired			5,653
Goodwill			799	$ 799	$ 797
Net assets acquired			$ 6,452
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
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
Accounts payable		27
Accrued liabilities and other current liabilities		21
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		509
Other long-term liabilities		0
Total liabilities assumed		769
Identifiable net assets acquired		2,862
Goodwill		799
Net assets acquired		$ 3,661
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
Cash	0
Accounts receivable	126
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	3,186
Accounts payable	96
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	395
Identifiable net assets acquired	2,791
Goodwill	0
Net assets acquired	$ 2,791

Acquisitions (Schedule of Ass51

Acquisitions (Schedule of Assets Acquired and Liabilities Assumed - Phantom) (Details) - USD ($) $ in Millions	Apr. 01, 2015	Apr. 02, 2015
EquiPower Acquisition
Business Acquisition [Line Items]
Number of shares issued	3,460,053
Current assets from risk management activities	$ 4
Intangible assets, current	67
Current liabilities from risk management activities	41
Intangible liabilities, current	$ 24
Duke Midwest Acquisition
Business Acquisition [Line Items]
Current assets from risk management activities		$ 30
Intangible assets, current		36
Current liabilities from risk management activities		0
Intangible liabilities, current		$ 58

Acquisitions (Pro Forma Results

Acquisitions (Pro Forma Results) (Details) - EquiPower and Duke Midwest Acquisitions $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Business Acquisition [Line Items]
Revenues	$ 3,844
Net income	442
Noncontrolling Interest
Business Acquisition [Line Items]
Net income	(3)
Parent
Business Acquisition [Line Items]
Net income	$ 445

Unconsolidated Investments (Det

Unconsolidated Investments (Details) $ in Millions	Aug. 03, 2016USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2016USD ($)	Sep. 30, 2015USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2015USD ($)	Apr. 01, 2015MW
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliate		$ 173		$ 173			$ 190
Identifiable net assets acquired						$ 5,653
Income from unconsolidated investments		4	$ (4)	7	$ (1)
Distributions from unconsolidated investment				1	3
Return of investment				14	8
Accounts receivable, net		374		374			402
Revenues		1,184	1,232	3,211	2,854
Impairments		212	$ 74	857	74
Elwood
Schedule of Equity Method Investments [Line Items]
Percent of voting interests acquired (as a percentage)								50.00%
Capacity of power facilities acquired | MW								1,580
Investment in unconsolidated affiliate		173		173			190
Identifiable net assets acquired		89		89
Distributions from unconsolidated investment				15	11
Return of investment				14	$ 8
Accounts receivable, net		10		10			$ 3
Collateral posted, expected to be released on closing	$ 35
Dynegy Marketing And Trade, LLC | Fuel Supply and Fuel Management Services Agreement | Elwood
Schedule of Equity Method Investments [Line Items]
Revenues		15		27
J-Power USA Development Co. Ltd | Elwood
Schedule of Equity Method Investments [Line Items]
Ownership interest, percentage	50.00%
Proceeds from Sale of Equity Method Investments	$ 173
Impairments		$ 9		$ 9

Risk Management Activities, D54

Risk Management Activities, Derivatives and Financial Instruments (Narratives) (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016USD ($)
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
Commodity Contract
Derivative [Line Items]
Credit risk derivative liabilities at fair value	$ 26
Fair value of collateral	$ 12

Risk Management Activities, D55

Risk Management Activities, Derivatives and Financial Instruments (Schedule of Derivative Contracts and Interest Rate Swaps) (Details) $ in Millions		Sep. 30, 2016USD ($)dollarswarranttBTUMWhshares	Dec. 31, 2015USD ($)
Derivative [Line Items]
Number of securities called by each warrant or right | shares		1
Not Designated as Hedging Instrument
Derivative [Line Items]
Margin and collateral netting		$ 73	$ 106
Not Designated as Hedging Instrument | Common stock warrants | Long
Derivative [Line Items]
Number of instruments held | warrant	[1]	16,000,000
Derivative Fair Value, Liability	[1],[2]	$ (2)
Not Designated as Hedging Instrument | Commodity Contract | Electricity derivatives | Short
Derivative [Line Items]
Number of instruments held | MWh	[3]	58,000,000
Derivative Fair Value, Liability	[2],[3]	$ 25
Not Designated as Hedging Instrument | Commodity Contract | Electricity basis derivatives | Short
Derivative [Line Items]
Number of instruments held | MWh	[4]	30,000,000
Derivative Fair Value, Liability	[2],[4]	$ (8)
Not Designated as Hedging Instrument | Commodity Contract | Natural gas derivatives | Long
Derivative [Line Items]
Number of instruments held | BTU	[3]	362,000,000
Derivative Fair Value, Liability	[2],[3]	$ (64)
Not Designated as Hedging Instrument | Commodity Contract | Natural gas basis derivatives | Long
Derivative [Line Items]
Number of instruments held | BTU		64,000,000
Derivative Fair Value, Liability	[2]	$ (22)
Not Designated as Hedging Instrument | Commodity Contract | Coal derivatives
Derivative [Line Items]
Number of instruments held | t	[5]	1,000,000
Not Designated as Hedging Instrument | Commodity Contract | Coal derivatives | Long
Derivative [Line Items]
Number of instruments held | t	[5]	0
Derivative Fair Value, Liability	[2],[5]	$ (7)
Not Designated as Hedging Instrument | Commodity Contract | Emissions derivatives | Long
Derivative [Line Items]
Number of instruments held | t		5,000,000
Derivative Fair Value, Liability	[2]	$ (5)
Not Designated as Hedging Instrument | Interest rate swaps | Long
Derivative [Line Items]
Number of instruments held | dollars		771,000,000
Derivative Fair Value, Liability	[2]	$ (40)
[1]	Each warrant is convertible into one share of Dynegy common stock.
[2]	Includes both asset and liability risk management positions but excludes margin and collateral netting of $73 million.
[3]	Mainly comprised of swaps, options, and physical forwards.
[4]	Comprised of FTRs and swaps.
[5]	Our net position rounds to less than 1 million tons.

Risk Management Activities, D56

Risk Management Activities, Derivatives and Financial Instruments (Schedule of Derivative Instruments in the Balance Sheet) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Risk Management Activities, Derivatives and Financial Instruments
Derivative Asset, Gross Fair Value	$ 351	$ 403
Derivative Asset, Contract Netting	(238)	(285)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	113	118
Derivative Liabilities, Gross Fair Value	(474)	(606)
Derivative Liability, Contract Netting	(238)	(285)
Margin and collateral netting	73	106
Derivative Liabilities, Net Fair Value	(163)	(215)
Derivative Assets (Liabilities), Gross Fair Value	(123)	(203)
Derivative Asset and Liability Contract Netting	0	0
Derivative Asset And Liability, Collateral, Obligation to Return Cash, Offset	73	106
Derivative Assets (Liabilities), Net Fair Value	(50)	(97)
Commodity Contract | Assets from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Asset, Gross Fair Value	351	403
Derivative Asset, Contract Netting	(238)	(285)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	113	118
Commodity Contract | Liabilities from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(432)	(557)
Derivative Liability, Contract Netting	(238)	(285)
Margin and collateral netting	73	106
Derivative Liabilities, Net Fair Value	(121)	(166)
Interest rate contracts | Liabilities from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(40)	(42)
Derivative Liability, Contract Netting	0	0
Margin and collateral netting	0	0
Derivative Liabilities, Net Fair Value	(40)	(42)
Common stock warrants | Other Liabilities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(2)	(7)
Derivative Liability, Contract Netting	0	0
Margin and collateral netting	0	0
Derivative Liabilities, Net Fair Value	$ (2)	$ (7)

Risk Management Activities, D57

Risk Management Activities, Derivatives and Financial Instruments (Schedule of Collateral Posted and Balance Sheet Location) (Details) - Commodity Contract - Prepayments and Other Current Assets - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Derivative [Line Items]
Gross collateral posted with counterparties	$ 119	$ 162
Less: Collateral netted against risk management liabilities	73	106
Net collateral within Prepayments and other current assets	$ 46	$ 56

Risk Management Activities, D58

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	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Commodity Contract | Revenues
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	$ (27)	$ 48	$ 188	$ 120
Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	1	(9)	(11)	(17)
Common stock warrants | Other income and (expense), net
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	$ 4	$ 45	$ 5	$ 43

Fair Value Measurements (Schedu

Fair Value Measurements (Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Assets:
Total assets from commodity risk management activities	$ 351	$ 403
Liabilities:
Liabilities from commodity risk management activities:	(432)	(557)
Liabilities from interest rate contracts	(40)	(42)
Total liabilities	(474)	(606)
Electricity contracts
Assets:
Assets from commodity risk management activities:	286	348
Liabilities:
Liabilities from commodity risk management activities:	(269)	(325)
Natural gas derivatives
Assets:
Assets from commodity risk management activities:	61	42
Liabilities:
Liabilities from commodity risk management activities:	(147)	(192)
Emissions derivatives
Assets:
Assets from commodity risk management activities:	3
Liabilities:
Liabilities from commodity risk management activities:	(8)
Diesel derivatives
Liabilities:
Liabilities from commodity risk management activities:		(4)
Coal derivatives
Assets:
Assets from commodity risk management activities:	1	13
Liabilities:
Liabilities from commodity risk management activities:	(8)	(36)
Liabilities from outstanding common stock warrants
Liabilities:
Liabilities from outstanding common stock warrants	(2)	(7)
Level 1
Assets:
Total 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	(2)	(7)
Level 1 | Electricity contracts
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
Liabilities:
Liabilities from commodity risk management activities:	0
Level 1 | Diesel derivatives
Liabilities:
Liabilities from commodity risk management activities:		0
Level 1 | Coal derivatives
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Liabilities from outstanding common stock warrants
Liabilities:
Liabilities from outstanding common stock warrants	(2)	(7)
Level 2
Assets:
Total assets from commodity risk management activities	302	358
Liabilities:
Liabilities from commodity risk management activities:	(360)	(464)
Liabilities from interest rate contracts	(40)	(42)
Total liabilities	(400)	(506)
Level 2 | Electricity contracts
Assets:
Assets from commodity risk management activities:	248	308
Liabilities:
Liabilities from commodity risk management activities:	(221)	(267)
Level 2 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	51	40
Liabilities:
Liabilities from commodity risk management activities:	(123)	(158)
Level 2 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	3
Liabilities:
Liabilities from commodity risk management activities:	(8)
Level 2 | Diesel derivatives
Liabilities:
Liabilities from commodity risk management activities:		(4)
Level 2 | Coal derivatives
Assets:
Assets from commodity risk management activities:	0	10
Liabilities:
Liabilities from commodity risk management activities:	(8)	(35)
Level 2 | Liabilities from outstanding common stock warrants
Liabilities:
Liabilities from outstanding common stock warrants	0	0
Level 3
Assets:
Total assets from commodity risk management activities	49	45
Liabilities:
Liabilities from commodity risk management activities:	(72)	(93)
Liabilities from interest rate contracts	0	0
Total liabilities	(72)	(93)
Level 3 | Electricity contracts
Assets:
Assets from commodity risk management activities:	38	40
Liabilities:
Liabilities from commodity risk management activities:	(48)	(58)
Level 3 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	10	2
Liabilities:
Liabilities from commodity risk management activities:	(24)	(34)
Level 3 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0
Level 3 | Diesel derivatives
Liabilities:
Liabilities from commodity risk management activities:		0
Level 3 | Coal derivatives
Assets:
Assets from commodity risk management activities:	1	3
Liabilities:
Liabilities from commodity risk management activities:	0	(1)
Level 3 | Liabilities from outstanding common stock warrants
Liabilities:
Liabilities from outstanding common stock warrants	$ 0	$ 0

Fair Value Measurements (Sensit

Fair Value Measurements (Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations) (Details) - Market Approach Valuation Technique - Level 3 - Fair Value, Measurements, Recurring T in Millions, MWh in Millions, BTU in Millions	9 Months Ended
	Sep. 30, 2016USD ($)BTUTMWh
Forward contracts - power
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | MWh	10	[1]
Fair value of derivatives held	$ (7,000,000)	[1]
Forward contracts - power | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread	5
Forward contracts - power | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread	$ 7
FTRs
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | MWh	26
Fair value of derivatives held	$ (3,000,000)
FTRs | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	0
FTRs | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	$ 6
Natural gas derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | BTU	78	[1]
Fair value of derivatives held	$ (14,000,000)	[1]
Natural gas derivatives | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	1.05
Natural gas derivatives | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	$ 1.35
Forward contracts - coal
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | T	0	[1]
Fair value of derivatives held	$ 1,000,000	[1]
Forward contracts - coal | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	6.10
Forward contracts - coal | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Forward price	$ 7.45
[1]	Represents forward financial and physical transactions at illiquid pricing locations.

Fair Value Measurements (Sche61

Fair Value Measurements (Schedule of Changes in Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Unrealized gain (loss) relating to instruments held at the end of the period				$ 75	$ 117
Level 3
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at the beginning of the period		$ (38)	$ (68)	(48)	(4)
Acquisitions					(72)
Total gains (losses) included in earnings		6	(1)	4	7
Settlements	[1]	9	7	21	7
Balance at the end of the period		(23)	(62)	(23)	(62)
Unrealized gain (loss) relating to instruments held at the end of the period		6	(1)	4	7
Level 3 | Electricity Derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at the beginning of the period		(24)	(54)	(18)	(4)
Acquisitions					(54)
Total gains (losses) included in earnings		9	2	4	7
Settlements	[1]	5	3	4	2
Balance at the end of the period		(10)	(49)	(10)	(49)
Unrealized gain (loss) relating to instruments held at the end of the period		9	2	4	7
Level 3 | Natural gas derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at the beginning of the period		(15)	(11)	(32)	0
Acquisitions					(14)
Total gains (losses) included in earnings		(4)	(3)	0	0
Settlements	[1]	5	0	18	0
Balance at the end of the period		(14)	(14)	(14)	(14)
Unrealized gain (loss) relating to instruments held at the end of the period		(4)	(3)	0	0
Level 3 | Heat Rate Derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at the beginning of the period			(7)		0
Acquisitions					(9)
Total gains (losses) included in earnings			0		0
Settlements	[1]		5		7
Balance at the end of the period			(2)		(2)
Unrealized gain (loss) relating to instruments held at the end of the period			0		0
Level 3 | Coal derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance at the beginning of the period		1	4	2	0
Acquisitions					5
Total gains (losses) included in earnings		1	0	0	0
Settlements	[1]	(1)	(1)	(1)	(2)
Balance at the end of the period		1	3	1	3
Unrealized gain (loss) relating to instruments held at the end of the period		$ 1	$ 0	$ 0	$ 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 (Sche62

Fair Value Measurements (Schedule of Financial Assets and Liabilities) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Not Designated as Hedging Instrument
Fair value of Financial Instruments
Margin and collateral netting		$ 73	$ 106
Commodity Contract | Prepayments and Other Current Assets
Fair value of Financial Instruments
Margin and collateral netting		$ 73	106
Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Stated interest rate		6.75%
Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Stated interest rate		7.375%
5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Stated interest rate		5.875%
Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Stated interest rate		7.625%
Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Stated interest rate		6.75%
Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Stated interest rate		7.375%
Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Stated interest rate		5.875%
Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Stated interest rate		7.625%
Dynegy, Inc. | TEUs - 7.00% Amortizing Notes, due 2019
Fair value of Financial Instruments
Stated interest rate		7.00%
Genco | Senior Notes Series H 7.00% Due 2018
Fair value of Financial Instruments
Stated interest rate		7.00%
Genco | Senior Notes Series I 6.30% Due 2020
Fair value of Financial Instruments
Stated interest rate		6.30%
Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Stated interest rate		7.95%
Carrying Amount | Dynegy, Inc. | Common stock warrants
Fair value of Financial Instruments
Common stock warrants		$ (2)	(7)
Carrying Amount | Dynegy, Inc. | Interest rate contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest rate derivatives		(40)	(42)
Carrying Amount | Dynegy, Inc. | Commodity Contract | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[1]	(81)	(154)
Carrying Amount | Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Long-term debt, gross	[2]	(2,081)	(2,077)
Carrying Amount | Dynegy, Inc. | Term Facilities Tranche B-2
Fair value of Financial Instruments
Long-term debt, gross	[2]	(762)	(766)
Carrying Amount | Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Long-term debt, gross	[2]	(1,731)	(1,729)
Carrying Amount | Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Long-term debt, gross	[2]	(492)	(491)
Carrying Amount | Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Long-term debt, gross	[2]	(1,236)	(1,235)
Carrying Amount | Dynegy, Inc. | TEUs - 7.00% Amortizing Notes, due 2019
Fair value of Financial Instruments
Long-term debt, gross	[2]	(84)	0
Carrying Amount | Dynegy, Inc. | Forward capacity agreement
Fair value of Financial Instruments
Long-term debt, gross	[2]	(203)	0
Carrying Amount | Dynegy, Inc. | Inventory financing agreements
Fair value of Financial Instruments
Long-term debt, gross		(136)	(136)
Carrying Amount | Dynegy, Inc. | Equipment financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[2]	(75)	(61)
Carrying Amount | Dynegy Finance IV, Inc. | Tranche C Term Loan, due 2023
Fair value of Financial Instruments
Long-term debt, gross	[2]	(1,995)	0
Carrying Amount | Genco | Senior Notes Series H 7.00% Due 2018
Fair value of Financial Instruments
Long-term debt, gross	[2]	(284)	(276)
Carrying Amount | Genco | Senior Notes Series I 6.30% Due 2020
Fair value of Financial Instruments
Long-term debt, gross	[2]	(218)	(213)
Carrying Amount | Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Long-term debt, gross	[2]	(226)	(225)
Fair Value | Dynegy, Inc. | Common stock warrants
Fair value of Financial Instruments
Common stock warrants		(2)	(7)
Fair Value | Dynegy, Inc. | Interest rate contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest rate derivatives		(40)	(42)
Fair Value | Dynegy, Inc. | Commodity Contract | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[1]	(81)	(154)
Fair Value | Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Long-term debt, gross	[2]	(2,168)	(1,985)
Fair Value | Dynegy, Inc. | Term Facilities Tranche B-2
Fair value of Financial Instruments
Long-term debt, gross	[2]	(779)	(754)
Fair Value | Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Long-term debt, gross	[2]	(1,724)	(1,531)
Fair Value | Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Long-term debt, gross	[2]	(450)	(404)
Fair Value | Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Long-term debt, gross	[2]	(1,225)	(1,078)
Fair Value | Dynegy, Inc. | TEUs - 7.00% Amortizing Notes, due 2019
Fair value of Financial Instruments
Long-term debt, gross	[2]	(88)	0
Fair Value | Dynegy, Inc. | Forward capacity agreement
Fair value of Financial Instruments
Long-term debt, gross	[2]	(203)	0
Fair Value | Dynegy, Inc. | Inventory financing agreements
Fair value of Financial Instruments
Long-term debt, gross		(135)	(137)
Fair Value | Dynegy, Inc. | Equipment financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[2]	(75)	(61)
Fair Value | Dynegy Finance IV, Inc. | Tranche C Term Loan, due 2023
Fair value of Financial Instruments
Long-term debt, gross	[2]	(2,015)	0
Fair Value | Genco | Senior Notes Series H 7.00% Due 2018
Fair value of Financial Instruments
Long-term debt, gross	[2]	(119)	(204)
Fair Value | Genco | Senior Notes Series I 6.30% Due 2020
Fair value of Financial Instruments
Long-term debt, gross	[2]	(99)	(148)
Fair Value | Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Long-term debt, gross	[2]	$ (107)	$ (162)
[1]	Carrying amounts exclude $73 million and $106 million of cash posted as collateral, as of September 30, 2016 and December 31, 2015, respectively.
[2]	Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 13—Debt for further discussion.

Accumulated Other Comprehensi63

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015
Accumulated Other Comprehensive Income [Roll Forward]
Beginning of period		$ 19	$ 20
Actuarial gain and plan amendments (net of tax of zero and $2, respectively)		0	7
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively)	[1]	(4)	(3)
Net current period other comprehensive income (loss), net of tax		(4)	4
End of period		15	24
Tax on actuarial gain and plan amendments		0	2
Tax on amortization of unrecognized prior service cost (credit) and actuarial loss (gain)	[1]	$ 0	$ 0
[1]	Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 16—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory (Summary of Inventori

Inventory (Summary of Inventories) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Dec. 31, 2015
Inventory Disclosure [Abstract]
Materials and supplies		$ 183	$ 178
Coal	[1]	233	350
Fuel oil	[1]	17	17
Emissions allowances	[2]	14	51
Other		0	1
Total		$ 447	$ 597
[1]	At September 30, 2016, approximately $47 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 13—Debt—Brayton Point Inventory Financing for further discussion.
[2]	At September 30, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 13—Debt—Emissions Repurchase Agreements for further discussion.

Inventory (Inventory Summary Fo

Inventory (Inventory Summary Footnote) (Details) - USD ($) $ in Millions		Sep. 30, 2016		Dec. 31, 2015
Inventory [Line Items]
Coal	[1]	$ 233		$ 350
Fuel oil	[1]	17		17
Inventory financing agreements
Inventory [Line Items]
Coal		47	[1]	44
Fuel oil		$ 16	[1]	$ 16
[1]	At September 30, 2016, approximately $47 million and $16 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 13—Debt—Brayton Point Inventory Financing for further discussion.

Property, Plant and Equipment66

Property, Plant and Equipment (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	$ 8,522	$ 9,235
Accumulated depreciation	(1,270)	(888)
Property, Plant and Equipment, Net	7,252	8,347
Power generation
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	7,481	8,178
Building and Building Improvements
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	938	956
Office and miscellaneous Equipment
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	$ 103	$ 101

Property, Plant and Equipment67

Property, Plant and Equipment (Narrative) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Property, Plant and Equipment [Line Items]
Impairments of long lived assets held for use	$ 212,000,000	$ 74,000,000	$ 857,000,000	$ 74,000,000
Asset impairment charges	212,000,000	74,000,000	857,000,000	74,000,000
Stuart Facility
Property, Plant and Equipment [Line Items]
Estimated fair value	0		0
Impairments of long lived assets held for use	55,000,000		$ 55,000,000
Baldwin Power Generation Facility | Power generation
Property, Plant and Equipment [Line Items]
Discount rate (as a percentage)			13.00%
Long-term growth rate (as a percentage)			2.50%
Estimated fair value	97,000,000		$ 97,000,000
Asset impairment charges			645,000,000
Newton Power Generation Facility
Property, Plant and Equipment [Line Items]
Asset impairment charges	$ 148,000,000		$ 148,000,000
Wood River Power Station
Property, Plant and Equipment [Line Items]
Impairments of long lived assets held for use		$ 74,000,000		$ 0

Joint Ownership of Generating68

Joint Ownership of Generating Facilities (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Property, plant and equipment		$ 8,522		$ 8,522		$ 9,235
Accumulated Depreciation		(1,270)		(1,270)		(888)
Property, plant and equipment, net		7,252		7,252		$ 8,347
Impairments		$ (212)	$ (74)	$ (857)	$ (74)
Miami Fort
Schedule of Equity Method Investments [Line Items]
Ownership Interest		64.00%		64.00%		64.00%
Property, plant and equipment		$ 206		$ 206		$ 207
Accumulated Depreciation		(33)		(33)		(16)
Construction Work in Progress		3		3		3
Property, plant and equipment, net		$ 176		$ 176		$ 194
J.M. Stuart
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	39.00%		39.00%		39.00%
Property, plant and equipment	[1]	$ 0		$ 0		$ 32
Accumulated Depreciation	[1]	0		0		(4)
Construction Work in Progress	[1]	0		0		20
Property, plant and equipment, net	[1]	$ 0		$ 0		$ 48
Conesville
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	40.00%		40.00%		40.00%
Property, plant and equipment	[1]	$ 61		$ 61		$ 61
Accumulated Depreciation	[1]	(2)		(2)		(2)
Construction Work in Progress	[1]	5		5		4
Property, plant and equipment, net	[1]	$ 64		$ 64		$ 63
W.M. Zimmer
Schedule of Equity Method Investments [Line Items]
Ownership Interest		46.50%		46.50%		46.50%
Property, plant and equipment		$ 116		$ 116		$ 99
Accumulated Depreciation		(21)		(21)		(10)
Construction Work in Progress		4		4		11
Property, plant and equipment, net		$ 99		$ 99		$ 100
Killen Station
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	33.00%		33.00%		33.00%
Property, plant and equipment	[1]	$ 18		$ 18		$ 17
Accumulated Depreciation	[1]	(1)		(1)		(1)
Construction Work in Progress	[1]	2		2		2
Property, plant and equipment, net	[1]	19		19		$ 18
Stuart Facility
Schedule of Equity Method Investments [Line Items]
Impairments		$ (55)		$ (55)
[1]	Facilities not operated by Dynegy.

Intangible Assets and Liabili69

Intangible Assets and Liabilities (Intangible Assets and Liabilities) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	$ 306	$ 306
Accumulated Amortization	(224)	(142)
Net Carrying Amount	82	164
Electricity Contract Liability, Gross	(28)	(30)
Electricity Contract Liability, Accumulated Amortization	26	19
Electricity Contract Liability, Net	(2)	(11)
Coal Contract Liability, Gross	(93)	(134)
Coal Contract Liability, Accumulated Amortization	76	82
Coal Contract Liability, Net	(17)	(52)
Coal Transport Contract Liability, Gross	(104)	(104)
Coal Transport Liability, Accumulated Amortization	85	64
Coal Transport Liability, Net	(19)	(40)
Gas Transport Contract Liability, Gross	(41)	(64)
Gas Transport Liability, Accumulated Amortization	7	27
Gas Transport Liability, Net	(34)	(37)
Intangible Liabilities, Gross	(266)	(332)
Intangible Liabilities, Accumulated Amortization	194	192
Intangible Liabilities, Net	(72)	(140)
Intangible Assets (Liabilities), Gross	40	(26)
Intangible Assets (Liabilities), Accumulated Amortization	(30)	50
Intangible Assets (Liabilities), Net	10	24
Electricity contracts
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	260	260
Accumulated Amortization	(187)	(126)
Net Carrying Amount	73	134
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	46	46
Accumulated Amortization	(37)	(16)
Net Carrying Amount	$ 9	$ 30

Intangible Assets and Liabili70

Intangible Assets and Liabilities (Amortization of Intangible Assets and Liabilities) (Details) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles		$ 4	$ (9)	$ 17	$ (18)
Electricity contracts, net
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[1]	19	21	52	53
Coal contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	(9)	(19)	(32)	(42)
Coal transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	(7)	(9)	(21)	(24)
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	$ 1	$ (2)	$ 18	$ (5)
[1]	The amortization of these contracts is recognized in Revenues in our unaudited consolidated statements of operations.
[2]	The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Tangible Equity Units (Details)

Tangible Equity Units (Details) - Tangible Equity Units - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2016
Tangible Equity Units [Line Items]
Number of units issued		4,600,000
Stated interest rate	7.00%	7.00%	7.00%
Unit price (in dollars per unit)	$ 100	$ 100	$ 100
Less: Issuance costs	$ 3	$ 14	$ 17
Net proceeds		$ 446	$ 443
Initial principal amount per unit (in dollars per unit)			$ 18.95
Observation period, consecutive trading days			20 days
Threshold appreciation price			$ 19.92
Initial reference price			$ 16.13
Minimum
Tangible Equity Units [Line Items]
Settlement rate per unit			5.0201
Maximum
Tangible Equity Units [Line Items]
Settlement rate per unit			6.1996
Secondary annual installments
Tangible Equity Units [Line Items]
Quarterly cash installment (in dollars per unit)			$ 1.75
Initial Installment, due October 1, 2016
Tangible Equity Units [Line Items]
Quarterly cash installment (in dollars per unit)			$ 1.94

Tangible Equity Units (Net Proc

Tangible Equity Units (Net Proceeds Schedule) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended	9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2016
Total
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 100	$ 100	$ 100
Gross proceeds			$ 460
Less: Issuance costs	$ (3)	$ (14)	(17)
Net proceeds		$ 446	$ 443
SPC
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 81		$ 81
Gross proceeds			$ 373
Less: Issuance costs			(14)
Net proceeds			$ 359
Amortizing Note
Tangible Equity Units [Line Items]
Price per TEU (in dollars per unit)	$ 19		$ 19
Gross proceeds			$ 87
Less: Issuance costs			(3)
Net proceeds			$ 84

Debt (Schedule of Long-term Deb

Debt (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions		Sep. 30, 2016	Mar. 18, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Carrying amount		$ 9,741		$ 7,416
Unamortized debt discounts and issuance costs (2)	[1]	(218)		(207)
Total Debt		9,523		7,209
Less: Current maturities, including unamortized debt discounts and issuance costs, net		167		80
Debt, long-term portion, net		$ 9,356		7,129
Forward capacity agreement
Debt Instrument [Line Items]
Carrying amount			$ 219
Senior Notes 6.75%, Due 2019
Debt Instrument [Line Items]
Stated interest rate		6.75%
Senior Notes 7.375%, Due 2022
Debt Instrument [Line Items]
Stated interest rate		7.375%
5.875% Senior Notes, Due June 2023
Debt Instrument [Line Items]
Stated interest rate		5.875%
Senior Notes 7.625%, Due 2024
Debt Instrument [Line Items]
Stated interest rate		7.625%
Secured and Unsecured Debt
Debt Instrument [Line Items]
Carrying amount		$ 8,916		6,591
Secured Debt
Debt Instrument [Line Items]
Carrying amount		$ 3,129		916
Dynegy, Inc. | TEUs - 7.00% Amortizing Notes, due 2019
Debt Instrument [Line Items]
Stated interest rate		7.00%
Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Debt Instrument [Line Items]
Stated interest rate		6.75%
Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Debt Instrument [Line Items]
Stated interest rate		7.375%
Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Debt Instrument [Line Items]
Stated interest rate		5.875%
Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Debt Instrument [Line Items]
Stated interest rate		7.625%
Dynegy, Inc. | Secured Debt | Tranche B-2 Term Loan, Due 2020
Debt Instrument [Line Items]
Carrying amount		$ 774		780
Dynegy, Inc. | Secured Debt | Revolving Facility
Debt Instrument [Line Items]
Carrying amount		0		0
Dynegy, Inc. | Secured Debt | Forward capacity agreement
Debt Instrument [Line Items]
Carrying amount		219		0
Dynegy, Inc. | Secured Debt | Inventory financing agreements
Debt Instrument [Line Items]
Carrying amount		136		136
Dynegy, Inc. | Unsecured Debt
Debt Instrument [Line Items]
Carrying amount		5,787		5,675
Dynegy, Inc. | Unsecured Debt | TEUs - 7.00% Amortizing Notes, due 2019
Debt Instrument [Line Items]
Carrying amount		87		0
Dynegy, Inc. | Unsecured Debt | Senior Notes 6.75%, Due 2019
Debt Instrument [Line Items]
Carrying amount		2,100		2,100
Dynegy, Inc. | Unsecured Debt | Senior Notes 7.375%, Due 2022
Debt Instrument [Line Items]
Carrying amount		1,750		1,750
Dynegy, Inc. | Unsecured Debt | 5.875% Senior Notes, Due June 2023
Debt Instrument [Line Items]
Carrying amount		500		500
Dynegy, Inc. | Unsecured Debt | Senior Notes 7.625%, Due 2024
Debt Instrument [Line Items]
Carrying amount		1,250		1,250
Dynegy, Inc. | Unsecured Debt | Equipment financing agreements
Debt Instrument [Line Items]
Carrying amount		100		75
Dynegy Finance IV, Inc. | Secured Debt | Tranche C Term Loan, due 2023
Debt Instrument [Line Items]
Carrying amount	[2]	2,000		0
Genco
Debt Instrument [Line Items]
Carrying amount		$ 825
Genco | Senior Notes Series H 7.00% Due 2018
Debt Instrument [Line Items]
Stated interest rate		7.00%
Genco | Senior Notes Series I 6.30% Due 2020
Debt Instrument [Line Items]
Stated interest rate		6.30%
Genco | Senior Notes Series F 7.95% Due 2032
Debt Instrument [Line Items]
Stated interest rate		7.95%
Genco | Unsecured Debt
Debt Instrument [Line Items]
Carrying amount	[3]	$ 825		825
Unamortized debt discounts and issuance costs (2)		(97)		(111)
Genco | Unsecured Debt | Senior Notes Series H 7.00% Due 2018
Debt Instrument [Line Items]
Carrying amount		300		300
Genco | Unsecured Debt | Senior Notes Series I 6.30% Due 2020
Debt Instrument [Line Items]
Carrying amount		250		250
Genco | Unsecured Debt | Senior Notes Series F 7.95% Due 2032
Debt Instrument [Line Items]
Carrying amount		$ 275		$ 275
[1]	Includes $97 million and $111 million of unamortized debt discounts as of September 30, 2016 and December 31, 2015, respectively, relating to the Genco unsecured obligations.
[2]	At September 30, 2016, the Tranche C Term Loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our unaudited consolidated balance sheet. Upon the closing of the Delta Transaction, this debt obligation will become Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion.
[3]	On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes. See Note 21—Subsequent Events—Genco Debt Restructure for further discussion.

Debt (Narratives) (Details)

Debt (Narratives) (Details)

Mar. 18, 2016USD ($)

Sep. 30, 2016USD ($)tranche$ / shares

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Oct. 11, 2016USD ($)

Jun. 30, 2016USD ($)

Jun. 27, 2016USD ($)

Dec. 31, 2015USD ($)

Aug. 14, 2015USD ($)

Apr. 02, 2015USD ($)

Apr. 01, 2015USD ($)

Sep. 18, 2014USD ($)

Dec. 02, 2013

Debt Instrument [Line Items]

Restricted cash

$ 2,000,000,000

$ 0

Long-term Debt

9,523,000,000

7,209,000,000

Carrying amount

9,741,000,000

7,416,000,000

Genco restricted payment interest coverage ratio minimum

[1]

1.75%

Genco additional indebtedness interest coverage ratio minimum

[2]

2.50%

Genco additional indebtedness debt-to-capital ratio maximum

[2]

60.00%

Restricted cash

85,000,000

39,000,000

5.875% Senior Notes, Due June 2023

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 500,000,000

Stated interest rate

5.875%

Revolving Facility

Debt Instrument [Line Items]

Number of tranches | tranche

3

Tranche C Term Loan, due 2023

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 2,000,000,000

Restricted cash

2,000,000,000

Escrow Agreement

Debt Instrument [Line Items]

Restricted cash

45,000,000

$ 70,000,000

Restricted cash released from escrow for interest payments

26,000,000

Letter of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 55,000,000

Letters of credit outstanding

(55,000,000)

Revolving Credit Facility, Tranche B

Debt Instrument [Line Items]

Line of credit facility, amount outstanding

$ 75,000,000

Forward capacity agreement

Debt Instrument [Line Items]

Proceeds from Issuance of Debt

$ 198,000,000

Carrying amount

$ 219,000,000

Effective interest rate

4.45%

Term Facilities Tranche B-2

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 800,000,000

Debt instrument term

7 years

Senior Notes 6.75%, Due 2019

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 2,100,000,000

Stated interest rate

6.75%

Senior Notes 7.375%, Due 2022

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 1,750,000,000

Stated interest rate

7.375%

Senior Notes 7.625%, Due 2024

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 1,250,000,000

Stated interest rate

7.625%

Term Facilities and Revolving Facility, (The Credit Agreement)

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 2,225,000,000

Illinois Power Marketing | Letter of Credit and Reimbursement Agreement

Debt Instrument [Line Items]

Savings deposits

19,000,000

Illinois Power Marketing | Letter of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 50,000,000

Letters of credit outstanding

(30,000,000)

Delta Stock Purchase Agreement

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 50,000,000

Dynegy, Inc. | 5.875% Senior Notes, Due June 2023

Debt Instrument [Line Items]

Stated interest rate

5.875%

Dynegy, Inc. | Equipment financing agreements

Debt Instrument [Line Items]

Unamortized discount

$ 25,000,000

Dynegy, Inc. | Senior Notes 6.75%, Due 2019

Debt Instrument [Line Items]

Stated interest rate

6.75%

Dynegy, Inc. | Senior Notes 7.375%, Due 2022

Debt Instrument [Line Items]

Stated interest rate

7.375%

Dynegy, Inc. | Senior Notes 7.625%, Due 2024

Debt Instrument [Line Items]

Stated interest rate

7.625%

Parent

Debt Instrument [Line Items]

Restricted cash

$ 0

Restricted cash

0

0

Parent | Senior Notes

Debt Instrument [Line Items]

Amount of unsecured senior notes

5,600,000,000

Genco

Debt Instrument [Line Items]

Carrying amount

$ 825,000,000

Genco | Senior Notes Series H 7.00% Due 2018

Debt Instrument [Line Items]

Stated interest rate

7.00%

RGGI Repurchase Agreement

Debt Instrument [Line Items]

Assets sold under agreements to repurchase, carrying amount

$ 78,000,000

$ 78,000,000

Assets sold under agreements to repurchase, carry rate

3.49%

Minimum

Debt Instrument [Line Items]

Projected interest coverage ratio determination period

1 year

Maximum

Debt Instrument [Line Items]

Projected interest coverage ratio determination period

2 years

Revolving Facility | Line of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 1,425,000,000

Line of credit facility, amount outstanding

0

Revolving Facility | Letter of Credit

Debt Instrument [Line Items]

Letters of credit outstanding

(327,000,000)

Interest expense

Debt Instrument [Line Items]

Restricted cash

25,000,000

Original Issue Discount

Debt Instrument [Line Items]

Restricted cash

20,000,000

EquiPower and Duke Midwest Acquisitions | Revolving Facility

Debt Instrument [Line Items]

Maximum borrowing capacity

1,500,000,000

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

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 675,000,000

EquiPower Acquisition | Inventory financing agreements

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 15,000,000

Letters of credit outstanding

(58,000,000)

Debt Instrument, Collateral Amount

$ 3,000,000

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

Debt Instrument [Line Items]

Maximum borrowing capacity

475,000,000

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

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 350,000,000

LIBOR | Inventory financing agreements

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

5.60%

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

0.25%

LIBOR | Tranche C Term Loan, due 2023

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

4.00%

LIBOR | Illinois Power Marketing

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

0.50%

LIBOR | Minimum | Tranche C Term Loan, due 2023

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

1.00%

Base Rate | Tranche C Term Loan, due 2023

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

3.00%

Coal contracts | Inventory financing agreements

Debt Instrument [Line Items]

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 [Line Items]

Inventory financing, debt obligation increase (as a percentage)

90.00%

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

10.00%

Carrying Amount | Dynegy, Inc. | Equipment financing agreements

Debt Instrument [Line Items]

Net present value of the payments

$ 75,000,000

Interest rate swaps | Term Facilities Tranche B-2

Debt Instrument [Line Items]

Derivative, notional amount

$ 771,000,000

Derivative, average fixed interest rate (as a percentage)

3.19%

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

1.00%

Unsecured Debt | Dynegy, Inc.

Debt Instrument [Line Items]

Carrying amount

$ 5,787,000,000

5,675,000,000

Unsecured Debt | Dynegy, Inc. | 5.875% Senior Notes, Due June 2023

Debt Instrument [Line Items]

Carrying amount

500,000,000

500,000,000

Unsecured Debt | Dynegy, Inc. | Equipment financing agreements

Debt Instrument [Line Items]

Carrying amount

100,000,000

75,000,000

Unsecured Debt | Dynegy, Inc. | Senior Notes 6.75%, Due 2019

Debt Instrument [Line Items]

Carrying amount

2,100,000,000

2,100,000,000

Unsecured Debt | Dynegy, Inc. | Senior Notes 7.375%, Due 2022

Debt Instrument [Line Items]

Carrying amount

1,750,000,000

1,750,000,000

Unsecured Debt | Dynegy, Inc. | Senior Notes 7.625%, Due 2024

Debt Instrument [Line Items]

Carrying amount

1,250,000,000

1,250,000,000

Unsecured Debt | Genco

Debt Instrument [Line Items]

Carrying amount

[3]

825,000,000

825,000,000

Unsecured Debt | Genco | Senior Notes Series H 7.00% Due 2018

Debt Instrument [Line Items]

Carrying amount

300,000,000

300,000,000

Secured Debt

Debt Instrument [Line Items]

Carrying amount

3,129,000,000

916,000,000

Secured Debt | Dynegy, Inc. | Inventory financing agreements

Debt Instrument [Line Items]

Carrying amount

136,000,000

136,000,000

Secured Debt | Dynegy, Inc. | Revolving Facility

Debt Instrument [Line Items]

Carrying amount

0

0

Secured Debt | Dynegy, Inc. | Forward capacity agreement

Debt Instrument [Line Items]

Carrying amount

$ 219,000,000

0

Secured Debt | Dynegy Finance IV, Inc. | Tranche C Term Loan, due 2023

Debt Instrument [Line Items]

Debt instrument term

7 years

Carrying amount

[4]

$ 2,000,000,000

$ 0

Forecasted repayments | Forward capacity agreement

Debt Instrument [Line Items]

Repayments of Debt

$ 109,000,000

$ 110,000,000

Amortizing Note

Debt Instrument [Line Items]

Gross proceeds

$ 87,000,000

Tangible Equity Units

Debt Instrument [Line Items]

Stated interest rate

7.00%

7.00%

Gross proceeds

$ 460,000,000

Secondary annual installments | Tangible Equity Units

Debt Instrument [Line Items]

Tangible Equity Units, Quarterly Cash Installment, Per Unit | $ / shares

$ 1.75

Initial Installment, due October 1, 2016 | Tangible Equity Units

Debt Instrument [Line Items]

Tangible Equity Units, Quarterly Cash Installment, Per Unit | $ / shares

$ 1.94

Subsequent Event | 8.00% Unsecured Senior Notes

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 750,000,000

Stated interest rate

8.00%

[1]

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

[2]

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

[3]

On October 14, 2016, we entered into a restructuring support agreement (“RSA”) with Genco and an ad hoc group of Genco bondholders (the “Ad Hoc Group”) to restructure the Genco Senior Notes. See Note 21—Subsequent Events—Genco Debt Restructure for further discussion.

[4]

At September 30, 2016, the Tranche C Term Loan, under the Finance IV Credit Agreement, was secured by first-priority liens on amounts in the applicable escrow account which was classified as long-term Restricted cash in our unaudited consolidated balance sheet. Upon the closing of the Delta Transaction, this debt obligation will become Dynegy Inc.’s secured obligation. Please read Finance IV Credit Agreement below for further discussion.

Commitments and Contingencies (

Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions	Dec. 16, 2014USD ($)	Sep. 30, 2010USD ($)	Jun. 30, 2007USD ($)	Sep. 30, 2016USD ($)state	Sep. 30, 2016USD ($)state
Gas Index Pricing Litigation | Pending Litigation
Loss Contingencies [Line Items]
Number of States with pending litigation | state				3	3
Illinova Generating Company | Illinova Generating Company Arbitration | Pending Litigation
Loss Contingencies [Line Items]
Payments for legal settlements			$ 17
Illinova Generating Company | Illinova Generating Company Arbitration | Judicial Ruling
Loss Contingencies [Line Items]
Value of damages awarded	$ 2.5	$ 17
Gain litigation settlement				$ 20	$ 20

Commitments and Contingencies76

Commitments and Contingencies (Other Commitments and Contingencies) (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jul. 31, 2013USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2012localized_areasurface_impoundment	Sep. 30, 2016$ / MWh	May 31, 2015complaint
Hennepin, East Dam
Loss Contingencies [Line Items]
Post-closure monitoring costs | $	$ 5
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]
Estimated cost for recommended closure alternative for impoundments | $		$ 10
Number of localized areas where groundwater standards were exceeded | surface_impoundment			2
MISO 2015-2016 Planning Resource Auction
Loss Contingencies [Line Items]
Number of complaints | complaint					3
Actions taken by FERC, 2016 and 2017 Reference level for capacity per day | $ / MWh				0
Pending Litigation | MISO 2015-2016 Planning Resource Auction
Loss Contingencies [Line Items]
Number of complaints | complaint					1

Commitments and Contingencies77

Commitments and Contingencies (Indemnifications and Guarantees) (Details) - USD ($)	Sep. 30, 2016	Jun. 27, 2016
Delta Stock Purchase Agreement | Parent
Loss Contingencies [Line Items]
Ownership interest, percentage		100.00%
LS Power Indemnities
Loss Contingencies [Line Items]
Number of claims and amount of accrued indemnifications, if any	$ 0
Guarantee Obligations | Delta Stock Purchase Agreement
Loss Contingencies [Line Items]
Purchaser's obligation to pay reverse termination fee		$ 132,000,000

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income Tax Contingency [Line Items]
Tax benefit (benefit) for application of effective state tax rates, in areas without valuation allowances	$ (1)	$ 7	$ 6	$ (14)
Current state tax expense (benefit)			14
EquiPower Acquisition
Income Tax Contingency [Line Items]
Increase (decrease) in net deferred tax liabilities		$ (21)	$ 3	$ (459)

Pension and Other Post-Employ79

Pension and Other Post-Employment Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Gain recognized in OCI from remeasurement		$ 15
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost benefits earned during period	$ 4	4	$ 12	$ 11
Interest cost on projected benefit obligation	5	4	15	13
Expected return on plan assets	(5)	(6)	(17)	(17)
Amortization of prior service credit	(1)	0	(1)	(1)
Net periodic benefit cost (gain)	3	2	9	6
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost benefits earned during period	0	1	0	1
Interest cost on projected benefit obligation	1	1	3	3
Expected return on plan assets	(1)	(1)	(3)	(3)
Amortization of prior service credit	(1)	(1)	(3)	(2)
Net periodic benefit cost (gain)	$ (1)	$ 0	$ (3)	$ (1)

Capital Stock (Details)

Capital Stock (Details) - USD ($)	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Jun. 30, 2016	Aug. 03, 2015
Class of Stock [Line Items]
Stock repurchase program, authorized amount							$ 250,000,000
Treasury stock acquired (shares)			4,996,299
Stock repurchased during the period, value			$ 127,000,000
Mandatory Convertible Preferred Stock
Class of Stock [Line Items]
Dividends	$ 5,000,000	$ 5,000,000	$ 5,000,000	$ 16,000,000	$ 17,000,000
Dividend declared (in dollars per share)	$ 1.34
Tangible Equity Units
Class of Stock [Line Items]
Number of units issued						4,600,000
Stated interest rate	7.00%	7.00%		7.00%		7.00%
Unit price (in dollars per unit)	$ 100	$ 100		$ 100		$ 100

Earnings (Loss) Per Share (Deta

Earnings (Loss) Per Share (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net income (loss)		$ (249)	$ (24)	$ (1,062)	$ 181
Less: Net loss attributable to noncontrolling interest		0	0	(2)	(3)
Income (loss) from continuing operations attributable to Dynegy Inc.		(249)	(24)	(1,060)	184
Less: Dividends on preferred stock		5	5	16	16
Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic earnings (loss) per share		(254)	(29)	(1,076)	168
Add: Dividends on preferred stock	[1]	0	0	0	(16)
Adjusted income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for diluted earnings (loss) per share		$ (254)	$ (29)	$ (1,076)	$ 184
Basic shares outstanding (shares)	[2]	140,000,000	126,000,000	126,000,000	126,000,000
Effect of dilutive securities (shares)	[3]	$ 0	$ 0	$ 0	$ 14
Diluted shares outstanding (shares)		140,000,000	126,000,000	126,000,000	140,000,000
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	[2]	$ (1.81)	$ (0.23)	$ (8.54)	$ 1.33
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share)	[3]	$ (1.81)	$ (0.23)	$ (8.54)	$ 1.31
Tangible Equity Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Basic shares outstanding (shares)			23,092,460	23,092,460
[1]	Excluded for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015 due to a net loss from continuing operations for the respective periods.
[2]	For the three and nine months ended September 30, 2016, the TEUs are assumed to be outstanding at the minimum settlement amount, or 23,092,460 shares, for weighted-average shares for basic earnings (loss) per share. Please read Note 12—Tangible Equity Units for further discussion.
[3]	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three and nine months ended September 30, 2016 and the three months ended September 30, 2015.

Earnings (Loss) Per Share (Anti

Earnings (Loss) Per Share (Anti-Dilutive Shares - Potentially Dilutive in the Future) (Details) - shares shares in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	39.2	32.4	39.2	15.6
Stock options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	2.8	1.8	2.8	0
Restricted stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	1.3	1.5	1.3	0
Performance stock units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	1.2	0.6	1.2	0
Common stock warrants
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	15.6	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	12.9	12.9	12.9	0
Prepaid stock purchase contract (TEUs)
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	5.4	0	5.4	0

Condensed Consolidating Finan83

Condensed Consolidating Financial Information (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016USD ($)
Condensed Financial Statements, Captions [Line Items]
Subsidiary percentage ownership	100.00%
Senior Notes | Dynegy, Inc.
Condensed Financial Statements, Captions [Line Items]
Amount of unsecured senior notes	$ 5,600,000,000

Condensed Consolidating Finan84

Condensed Consolidating Financial Information (Balance Sheets) (Details) - USD ($) $ in Millions	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 1,458		$ 505	$ 934	$ 1,870
Restricted cash	85		39
Accounts receivable, net	374		402
Inventory	447		597
Other current assets	275		389
Total Current Assets	2,639		1,932
Property, plant and equipment, net	7,252		8,347
Investment in unconsolidated affiliate	173		190
Restricted cash	2,000		0
Goodwill	799	$ 799	797
Other long-term assets	161		193
Intercompany note receivable	0		0
Total Assets	13,024		11,459	12,157
Current Liabilities
Accounts payable	263		292
Other current liabilities	648		517
Total Current Liabilities	911		809
Debt, long-term portion	9,356		7,129
Intercompany note payable	0		0
Other long-term liabilities	550		602
Total Liabilities	10,817		8,540
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,211		2,921
Intercompany note receivable	0		0
Total Dynegy Stockholders’ Equity	2,211		2,921
Noncontrolling interest	(4)		(2)
Total Equity	2,207		2,919
Total Liabilities and Equity	13,024		11,459
Eliminations
Current Assets
Cash and cash equivalents	0		0	0	0
Restricted cash	0		0
Accounts receivable, net	(2,259)		(1,730)
Inventory	0		0
Other current assets	(2)		(14)
Total Current Assets	(2,261)		(1,744)
Property, plant and equipment, net	0		0
Investment in unconsolidated affiliate	(12,335)		(13,017)
Restricted cash	0
Goodwill	0		0
Other long-term assets	0		0
Intercompany note receivable	(3)		(17)
Total Assets	(14,599)		(14,778)
Current Liabilities
Accounts payable	(2,259)		(1,730)
Other current liabilities	(2)		(14)
Total Current Liabilities	(2,261)		(1,744)
Debt, long-term portion	0		0
Intercompany note payable	(3,042)		(3,059)
Other long-term liabilities	(3)		0
Total Liabilities	(5,306)		(4,803)
Stockholders’ Equity
Dynegy Stockholders’ Equity	(12,335)		(13,017)
Intercompany note receivable	3,042		3,042
Total Dynegy Stockholders’ Equity	(9,293)		(9,975)
Noncontrolling interest	0		0
Total Equity	(9,293)		(9,975)
Total Liabilities and Equity	(14,599)		(14,778)
Parent
Current Assets
Cash and cash equivalents	1,248		327	579	1,642
Restricted cash	0		0
Accounts receivable, net	115		499
Inventory	0		0
Other current assets	11		13
Total Current Assets	1,374		839
Property, plant and equipment, net	0		0
Investment in unconsolidated affiliate	12,335		13,017
Restricted cash	0
Goodwill	0		0
Other long-term assets	4		10
Intercompany note receivable	0		17
Total Assets	13,713		13,883
Current Liabilities
Accounts payable	1,745		1,388
Other current liabilities	224		92
Total Current Liabilities	1,969		1,480
Debt, long-term portion	6,355		6,293
Intercompany note payable	3,042		3,042
Other long-term liabilities	136		147
Total Liabilities	11,502		10,962
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,211		2,921
Intercompany note receivable	0		0
Total Dynegy Stockholders’ Equity	2,211		2,921
Noncontrolling interest	0		0
Total Equity	2,211		2,921
Total Liabilities and Equity	13,713		13,883
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	69		94	176	54
Restricted cash	0		0
Accounts receivable, net	2,383		1,503
Inventory	234		331
Other current assets	235		335
Total Current Assets	2,921		2,263
Property, plant and equipment, net	6,901		7,813
Investment in unconsolidated affiliate	173		190
Restricted cash	0
Goodwill	799		797
Other long-term assets	112		133
Intercompany note receivable	0		0
Total Assets	10,906		11,196
Current Liabilities
Accounts payable	226		238
Other current liabilities	293		277
Total Current Liabilities	519		515
Debt, long-term portion	288		122
Intercompany note payable	0		0
Other long-term liabilities	287		317
Total Liabilities	1,094		954
Stockholders’ Equity
Dynegy Stockholders’ Equity	12,854		13,284
Intercompany note receivable	(3,042)		(3,042)
Total Dynegy Stockholders’ Equity	9,812		10,242
Noncontrolling interest	0		0
Total Equity	9,812		10,242
Total Liabilities and Equity	10,906		11,196
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	141		84	$ 179	$ 174
Restricted cash	85		39
Accounts receivable, net	135		130
Inventory	213		266
Other current assets	31		55
Total Current Assets	605		574
Property, plant and equipment, net	351		534
Investment in unconsolidated affiliate	0		0
Restricted cash	2,000
Goodwill	0		0
Other long-term assets	45		50
Intercompany note receivable	3		0
Total Assets	3,004		1,158
Current Liabilities
Accounts payable	551		396
Other current liabilities	133		162
Total Current Liabilities	684		558
Debt, long-term portion	2,713		714
Intercompany note payable	0		17
Other long-term liabilities	130		138
Total Liabilities	3,527		1,427
Stockholders’ Equity
Dynegy Stockholders’ Equity	(519)		(267)
Intercompany note receivable	0		0
Total Dynegy Stockholders’ Equity	(519)		(267)
Noncontrolling interest	(4)		(2)
Total Equity	(523)		(269)
Total Liabilities and Equity	$ 3,004		$ 1,158

Condensed Consolidating Finan85

Condensed Consolidating Financial Information (Operations) (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 1,184,000	$ 1,232,000	$ 3,211,000	$ 2,854,000
Cost of sales, excluding depreciation expense	(660,000)	(621,000)	(1,698,000)	(1,494,000)
Gross margin	524,000	611,000	1,513,000	1,360,000
Operating and maintenance expense	(218,000)	(219,000)	(695,000)	(580,000)
Depreciation expense	(163,000)	(174,000)	(494,000)	(413,000)
Impairments	(212,000)	(74,000)	(857,000)	(74,000)
General and administrative expense	(41,000)	(29,000)	(117,000)	(94,000)
Acquisition and integration costs	(7,000)	(8,000)	(8,000)	(121,000)
Other	0	0	(16,000)	(1,000)
Operating income (loss)	(117,000)	107,000	(674,000)	77,000
Earnings (losses) from unconsolidated investment	4,000	(4,000)	7,000	(1,000)
Equity in earnings from investments in affiliates	0	0	0	0
Interest Expense	(166,000)	(145,000)	(449,000)	(413,000)
Other income and expense, net	29,000	46,000	60,000	45,000
Income (loss) before income taxes	(250,000)	4,000	(1,056,000)	(292,000)
Income tax benefit (expense)	1,000	(28,000)	(6,000)	473,000
Net income (loss)	(249,000)	(24,000)	(1,062,000)	181,000
Less: Comprehensive income (loss) attributable to noncontrolling interest	0	0	(2,000)	(3,000)
Net Income (Loss) Attributable to Parent	(249,000)	(24,000)	(1,060,000)	184,000
Eliminations
Condensed Financial Statements, Captions [Line Items]
Revenues	(2,000)	105,000	(2,000)	(4,000)
Cost of sales, excluding depreciation expense	2,000	(105,000)	2,000	4,000
Gross margin	0	0	0	0
Operating and maintenance expense	0	0	0	0
Depreciation expense	0	0	0	0
Impairments	0	0	0	0
General and administrative expense	0	0	0	0
Acquisition and integration costs	0	0	0	0
Other	0		0	0
Operating income (loss)	0	0	0	0
Earnings (losses) from unconsolidated investment	0	0	0	0
Equity in earnings from investments in affiliates	153,000	(53,000)	718,000	(500,000)
Interest Expense	1,000	0	2,000	0
Other income and expense, net	(1,000)	0	(2,000)	0
Income (loss) before income taxes	153,000	(53,000)	718,000	(500,000)
Income tax benefit (expense)	0	0	0	0
Net income (loss)	153,000	(53,000)	718,000	(500,000)
Less: Comprehensive income (loss) attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	153,000	(53,000)	718,000	(500,000)
Parent
Condensed Financial Statements, Captions [Line Items]
Revenues	0	0	0	0
Cost of sales, excluding depreciation expense	0	0	0	0
Gross margin	0	0	0	0
Operating and maintenance expense	0	0	0	0
Depreciation expense	0	0	0	0
Impairments	0	0	0	0
General and administrative expense	(2,000)	3,000	(5,000)	0
Acquisition and integration costs	(5,000)	0	(8,000)	0
Other	0		0	0
Operating income (loss)	(7,000)	3,000	(13,000)	0
Earnings (losses) from unconsolidated investment	0	0	0	0
Equity in earnings from investments in affiliates	(153,000)	53,000	(718,000)	500,000
Interest Expense	(112,000)	(127,000)	(355,000)	(361,000)
Other income and expense, net	23,000	47,000	26,000	45,000
Income (loss) before income taxes	(249,000)	(24,000)	(1,060,000)	184,000
Income tax benefit (expense)	0	0	0	0
Net income (loss)	(249,000)	(24,000)	(1,060,000)	184,000
Less: Comprehensive income (loss) attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	(249,000)	(24,000)	(1,060,000)	184,000
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues	919,000	878,000	2,517,000	2,186,000
Cost of sales, excluding depreciation expense	(501,000)	(369,000)	(1,295,000)	(1,080,000)
Gross margin	418,000	509,000	1,222,000	1,106,000
Operating and maintenance expense	(152,000)	(154,000)	(503,000)	(385,000)
Depreciation expense	(147,000)	(149,000)	(433,000)	(352,000)
Impairments	(64,000)	(74,000)	(709,000)	(74,000)
General and administrative expense	(28,000)	(26,000)	(87,000)	(69,000)
Acquisition and integration costs	0	(8,000)	(3,000)	(121,000)
Other	(1,000)		(1,000)	(1,000)
Operating income (loss)	26,000	98,000	(514,000)	104,000
Earnings (losses) from unconsolidated investment	4,000	(4,000)	7,000	(1,000)
Equity in earnings from investments in affiliates	0	0	0	0
Interest Expense	(5,000)	0	(9,000)	0
Other income and expense, net	5,000	(1,000)	20,000	0
Income (loss) before income taxes	30,000	93,000	(496,000)	103,000
Income tax benefit (expense)	37,000	(45,000)	30,000	473,000
Net income (loss)	67,000	48,000	(466,000)	576,000
Less: Comprehensive income (loss) attributable to noncontrolling interest	0	0	0	0
Net Income (Loss) Attributable to Parent	67,000	48,000	(466,000)	576,000
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues	267,000	249,000	696,000	672,000
Cost of sales, excluding depreciation expense	(161,000)	(147,000)	(405,000)	(418,000)
Gross margin	106,000	102,000	291,000	254,000
Operating and maintenance expense	(66,000)	(65,000)	(192,000)	(195,000)
Depreciation expense	(16,000)	(25,000)	(61,000)	(61,000)
Impairments	(148,000)	0	(148,000)	0
General and administrative expense	(11,000)	(6,000)	(25,000)	(25,000)
Acquisition and integration costs	(2,000)	0	3,000	0
Other	1,000		(15,000)	0
Operating income (loss)	(136,000)	6,000	(147,000)	(27,000)
Earnings (losses) from unconsolidated investment	0	0	0	0
Equity in earnings from investments in affiliates	0	0	0	0
Interest Expense	(50,000)	(18,000)	(87,000)	(52,000)
Other income and expense, net	2,000	0	16,000	0
Income (loss) before income taxes	(184,000)	(12,000)	(218,000)	(79,000)
Income tax benefit (expense)	(36,000)	17,000	(36,000)	0
Net income (loss)	(220,000)	5,000	(254,000)	(79,000)
Less: Comprehensive income (loss) attributable to noncontrolling interest	0	0	(2,000)	(3,000)
Net Income (Loss) Attributable to Parent	$ (220,000)	$ 5,000	$ (252,000)	$ (76,000)

Condensed Consolidating Finan86

Condensed Consolidating Financial Information (Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ (249)	$ (24)	$ (1,062)	$ 181
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)	0	13	0	8
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	(2)	(1)	(4)	(3)
Other comprehensive income from investment in affiliates	0	0	0	0
Other comprehensive income (loss), net of tax	(2)	12	(4)	5
Comprehensive income (loss)	(251)	(12)	(1,066)	186
Comprehensive income (loss) attributable to noncontrolling interest	0	1	(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.	(251)	(13)	(1,064)	188
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	153	(53)	718	(500)
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)		0		0
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	0	0	0	0
Other comprehensive income from investment in affiliates	1	(7)	1	(7)
Other comprehensive income (loss), net of tax	1	(7)	1	(7)
Comprehensive income (loss)	154	(60)	719	(507)
Comprehensive income (loss) attributable to noncontrolling interest	0	(1)	0	(1)
Total comprehensive income (loss) attributable to Dynegy Inc.	154	(59)	719	(506)
Parent
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(249)	(24)	(1,060)	184
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)		6		1
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	(1)	(1)	(3)	(3)
Other comprehensive income from investment in affiliates	(1)	7	(1)	7
Other comprehensive income (loss), net of tax	(2)	12	(4)	5
Comprehensive income (loss)	(251)	(12)	(1,064)	189
Comprehensive income (loss) attributable to noncontrolling interest	0	1	0	1
Total comprehensive income (loss) attributable to Dynegy Inc.	(251)	(13)	(1,064)	188
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	67	48	(466)	576
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)		0		0
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	0	0	0	0
Other comprehensive income from investment in affiliates	0	0	0	0
Other comprehensive income (loss), net of tax	0	0	0	0
Comprehensive income (loss)	67	48	(466)	576
Comprehensive income (loss) attributable to noncontrolling interest	0	0	0	0
Total comprehensive income (loss) attributable to Dynegy Inc.	67	48	(466)	576
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	(220)	5	(254)	(79)
Actuarial gain and plan amendments (net of tax of zero, $2, zero, and $2 for each respective period)		7		7
Amortization of unrecognized prior service credit (net of tax of zero for each respective period)	(1)	0	(1)	0
Other comprehensive income from investment in affiliates	0	0	0	0
Other comprehensive income (loss), net of tax	(1)	7	(1)	7
Comprehensive income (loss)	(221)	12	(255)	(72)
Comprehensive income (loss) attributable to noncontrolling interest	0	1	(2)	(2)
Total comprehensive income (loss) attributable to Dynegy Inc.	$ (221)	$ 11	$ (253)	$ (70)

Condensed Consolidating Finan87

Condensed Consolidating Financial Information (Cash Flow) (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 649	$ 302
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(259)	(171)
Acquisitions, net of cash acquired	0	(6,078)
Decrease (increase) in restricted cash	(2,045)	5,148
Net intercompany transfers	0	0
Distributions from unconsolidated affiliate	14	8
Other investing	10	(6)
Net cash provided by (used in) investing activities	(2,280)	(1,099)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	2,277	57
Repayments of borrowings	(21)	(29)
Proceeds from issuance of equity, net of issuance costs	359	(6)
Preferred stock dividends paid	(16)	(17)
Interest rate swap settlement payments	(13)	(13)
Net intercompany transfers	0	0
Repurchase of common stock	0	(127)
Other financing	(2)	(4)
Net cash provided by (used in) financing activities	2,584	(139)
Net increase (decrease) in cash and cash equivalents	953	(936)
Cash and cash equivalents, beginning of period	505	1,870
Cash and cash equivalents, end of period	1,458	934
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	0	0
Acquisitions, net of cash acquired		0
Decrease (increase) in restricted cash	0	0
Net intercompany transfers	(670)	(349)
Distributions from unconsolidated affiliate	0	0
Other investing	0	0
Net cash provided by (used in) investing activities	(670)	(349)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	0	0
Repayments of borrowings	0	0
Proceeds from issuance of equity, net of issuance costs	0	0
Preferred stock dividends paid	0	0
Interest rate swap settlement payments	0	0
Net intercompany transfers	670	349
Repurchase of common stock		0
Other financing	0	0
Net cash provided by (used in) financing activities	670	349
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	0	0
Parent
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	(155)	(141)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	0	(8)
Acquisitions, net of cash acquired		(6,207)
Decrease (increase) in restricted cash	0	5,148
Net intercompany transfers	670	349
Distributions from unconsolidated affiliate	0	0
Other investing	0	0
Net cash provided by (used in) investing activities	670	(718)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	84	(31)
Repayments of borrowings	(6)	(6)
Proceeds from issuance of equity, net of issuance costs	359	(6)
Preferred stock dividends paid	(16)	(17)
Interest rate swap settlement payments	(13)	(13)
Net intercompany transfers	0	0
Repurchase of common stock		(127)
Other financing	(2)	(4)
Net cash provided by (used in) financing activities	406	(204)
Net increase (decrease) in cash and cash equivalents	921	(1,063)
Cash and cash equivalents, beginning of period	327	1,642
Cash and cash equivalents, end of period	1,248	579
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	780	502
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(227)	(122)
Acquisitions, net of cash acquired		29
Decrease (increase) in restricted cash	0	0
Net intercompany transfers	0	0
Distributions from unconsolidated affiliate	14	8
Other investing	10	(6)
Net cash provided by (used in) investing activities	(203)	(91)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	198	78
Repayments of borrowings	(15)	(23)
Proceeds from issuance of equity, net of issuance costs	0	0
Preferred stock dividends paid	0	0
Interest rate swap settlement payments	0	0
Net intercompany transfers	(785)	(344)
Repurchase of common stock		0
Other financing	0	0
Net cash provided by (used in) financing activities	(602)	(289)
Net increase (decrease) in cash and cash equivalents	(25)	122
Cash and cash equivalents, beginning of period	94	54
Cash and cash equivalents, end of period	69	176
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	24	(59)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	(32)	(41)
Acquisitions, net of cash acquired		100
Decrease (increase) in restricted cash	(2,045)	0
Net intercompany transfers	0	0
Distributions from unconsolidated affiliate	0	0
Other investing	0	0
Net cash provided by (used in) investing activities	(2,077)	59
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term borrowings, net of debt issuance costs	1,995	10
Repayments of borrowings	0	0
Proceeds from issuance of equity, net of issuance costs	0	0
Preferred stock dividends paid	0	0
Interest rate swap settlement payments	0	0
Net intercompany transfers	115	(5)
Repurchase of common stock		0
Other financing	0	0
Net cash provided by (used in) financing activities	2,110	5
Net increase (decrease) in cash and cash equivalents	57	5
Cash and cash equivalents, beginning of period	84	174
Cash and cash equivalents, end of period	$ 141	$ 179

Segment Information (Narrative)

Segment Information (Narrative) (Details)	9 Months Ended
	Sep. 30, 2016segment
Segment Reporting [Abstract]
Number of reportable segments	3

Segment Information (Segment Re

Segment Information (Segment Reporting) (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Segment Information
Unaffiliated revenues	$ 1,168,000,000	$ 1,232,000,000	$ 3,184,000,000	$ 2,854,000,000
Intercompany revenues	16,000,000	0	27,000,000	0
Revenues	1,184,000,000	1,232,000,000	3,211,000,000	2,854,000,000
Depreciation expense	(163,000,000)	(174,000,000)	(494,000,000)	(413,000,000)
Impairments	(212,000,000)	(74,000,000)	(857,000,000)	(74,000,000)
General and administrative expense	(41,000,000)	(29,000,000)	(117,000,000)	(94,000,000)
Acquisition and integration costs	(7,000,000)	(8,000,000)	(8,000,000)	(121,000,000)
Operating income (loss)	(117,000,000)	107,000,000	(674,000,000)	77,000,000
Earnings (losses) from unconsolidated investment	4,000,000	(4,000,000)	7,000,000	(1,000,000)
Interest expense	(166,000,000)	(145,000,000)	(449,000,000)	(413,000,000)
Other items, net	29,000,000	46,000,000	60,000,000	45,000,000
Income (loss) before income taxes	(250,000,000)	4,000,000	(1,056,000,000)	(292,000,000)
Income tax benefit (expense)	1,000,000	(28,000,000)	(6,000,000)	473,000,000
Net income (loss)	(249,000,000)	(24,000,000)	(1,062,000,000)	181,000,000
Less: Net loss attributable to noncontrolling interest	0	0	(2,000,000)	(3,000,000)
Net loss attributable to Dynegy Inc.	(249,000,000)	(24,000,000)	(1,060,000,000)	184,000,000
Identifiable assets (domestic)	13,024,000,000	12,157,000,000	13,024,000,000	12,157,000,000	$ 11,459,000,000
Investment in unconsolidated affiliate	173,000,000	189,000,000	173,000,000	189,000,000
Capital expenditures	(35,000,000)	(69,000,000)	(259,000,000)	(171,000,000)
Operating segments
Segment Information
Depreciation expense
Investment in unconsolidated affiliate	0	0	0	0
Operating segments | Coal
Segment Information
Unaffiliated revenues	388,000,000	410,000,000	1,022,000,000	976,000,000
Intercompany revenues	0	(14,000,000)	(24,000,000)	(131,000,000)
Revenues	388,000,000	396,000,000	998,000,000	845,000,000
Depreciation expense	(27,000,000)	(39,000,000)	(99,000,000)	(96,000,000)
Impairments	(55,000,000)	(74,000,000)	(700,000,000)	(74,000,000)
General and administrative expense	0	0	0	0
Acquisition and integration costs	0	0	0	0
Operating income (loss)	(33,000,000)	(36,000,000)	(728,000,000)	(34,000,000)
Earnings (losses) from unconsolidated investment	0	0	0	0
Interest expense	0	0	0	0
Other items, net	3,000,000	0	9,000,000	0
Identifiable assets (domestic)	1,432,000,000	2,426,000,000	1,432,000,000	2,426,000,000
Capital expenditures	(8,000,000)	(25,000,000)	(47,000,000)	(44,000,000)
Operating segments | IPH
Segment Information
Unaffiliated revenues	241,000,000	221,000,000	575,000,000	629,000,000
Intercompany revenues	1,000,000	0	(1,000,000)	(4,000,000)
Revenues	242,000,000	221,000,000	574,000,000	625,000,000
Depreciation expense	(7,000,000)	(8,000,000)	(21,000,000)	(24,000,000)
Impairments	(148,000,000)	0	(148,000,000)	0
General and administrative expense	0	0	0	0
Acquisition and integration costs	0	0	8,000,000	0
Operating income (loss)	(104,000,000)	31,000,000	(87,000,000)	39,000,000
Earnings (losses) from unconsolidated investment	0	0	0	0
Interest expense	0	0	0	0
Other items, net	1,000,000	0	15,000,000	0
Identifiable assets (domestic)	746,000,000	993,000,000	746,000,000	993,000,000
Investment in unconsolidated affiliate	0	0	0	0
Capital expenditures	(11,000,000)	(12,000,000)	(32,000,000)	(41,000,000)
Operating segments | Gas
Segment Information
Unaffiliated revenues	539,000,000	605,000,000	1,587,000,000	1,254,000,000
Intercompany revenues	15,000,000	10,000,000	52,000,000	130,000,000
Revenues	554,000,000	615,000,000	1,639,000,000	1,384,000,000
Depreciation expense	(128,000,000)	(126,000,000)	(370,000,000)	(290,000,000)
Impairments	(9,000,000)	0	(9,000,000)	0
General and administrative expense	0	0	0	0
Acquisition and integration costs	0	0	0	0
Operating income (loss)	69,000,000	152,000,000	279,000,000	290,000,000
Earnings (losses) from unconsolidated investment	4,000,000	(4,000,000)	7,000,000	(1,000,000)
Interest expense	0	0	0	0
Other items, net	0	0	12,000,000	0
Identifiable assets (domestic)	7,498,000,000	7,948,000,000	7,498,000,000	7,948,000,000
Investment in unconsolidated affiliate	173,000,000	189,000,000	173,000,000	189,000,000
Capital expenditures	(15,000,000)	(29,000,000)	(171,000,000)	(78,000,000)
Other and Eliminations
Segment Information
Unaffiliated revenues	0	(4,000,000)	0	(5,000,000)
Intercompany revenues	0	4,000,000	0	5,000,000
Revenues	0	0	0	0
Depreciation expense	(1,000,000)	(1,000,000)	(4,000,000)	(3,000,000)
Impairments	0	0	0	0
General and administrative expense	(41,000,000)	(29,000,000)	(117,000,000)	(94,000,000)
Acquisition and integration costs	(7,000,000)	(8,000,000)	(16,000,000)	(121,000,000)
Operating income (loss)	(49,000,000)	(40,000,000)	(138,000,000)	(218,000,000)
Earnings (losses) from unconsolidated investment	0	0	0	0
Interest expense	(166,000,000)	(145,000,000)	(449,000,000)	(413,000,000)
Other items, net	25,000,000	46,000,000	24,000,000	45,000,000
Income tax benefit (expense)	1,000,000	(28,000,000)	(6,000,000)
Identifiable assets (domestic)	3,348,000,000	790,000,000	3,348,000,000	790,000,000
Investment in unconsolidated affiliate	0	0	0	0
Capital expenditures	$ (1,000,000)	$ (3,000,000)	$ (9,000,000)	$ (8,000,000)

Subsequent Events (Details)

Subsequent Events (Details) - USD ($) $ / shares in Units, shares in Millions	Oct. 14, 2016	Sep. 30, 2016	Sep. 30, 2015	Oct. 24, 2016	Oct. 11, 2016
Subsequent Event [Line Items]
Distributions from unconsolidated affiliate		$ 14,000,000	$ 8,000,000
Subsequent Event | 8.00% Unsecured Senior Notes
Subsequent Event [Line Items]
Amount of unsecured senior notes					$ 750,000,000
Stated interest rate					8.00%
Subsequent Event | Affiliate | Genco and Ad Hock Group of Shareholders
Subsequent Event [Line Items]
Payments of debt restructuring costs	$ 139,000,000
Subsequent Event | Restructuring Support Agreement | Affiliate | Genco and Ad Hock Group of Shareholders
Subsequent Event [Line Items]
Payments of debt restructuring costs	9,000,000
Distributions from unconsolidated affiliate	$ 61,000,000
Warrants and rights outstanding	10
Plan of reorganization, term of warrants	7 years
Warrants, exercise price (USD per share)	$ 35
Aggregate percent of of principal holders acceptance needed for out of court restructuring	97.00%
Aggregate percent of principal holders acceptance for pre-packaged Chapter 11	66.70%
Ad Hoc Group of bondholders, Percent				70.00%
Subsequent Event | Restructuring Support Agreement | Affiliate | Genco and Ad Hock Group of Shareholders | Genco Senior Notes Series F, H, and I
Subsequent Event [Line Items]
Amount of unsecured senior notes	$ 825,000,000
Subsequent Event | Restructuring Support Agreement | Affiliate | Genco and Ad Hock Group of Shareholders | Unsecured Debt
Subsequent Event [Line Items]
Amount of unsecured senior notes	$ 210,000,000