Dyne Therapeutics 10-Q 4 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 19, 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	Mar. 31, 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		117,278,604
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 821	$ 505
Restricted cash	37	39
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively	339	402
Inventory	579	597
Assets from risk management activities	177	100
Intangible assets	81	102
Prepayments and other current assets	247	187
Total Current Assets	2,281	1,932
Property, Plant and Equipment, Net	8,242	8,347
Investment in unconsolidated affiliate	185	190
Assets from risk management activities	52	18
Goodwill	797	797
Intangible assets	44	62
Other long-term assets	107	113
Total Assets	11,708	11,459
Current Liabilities
Accounts payable	243	292
Accrued interest	180	74
Intangible liabilities	65	85
Accrued liabilities and other current liabilities	99	125
Liabilities from risk management activities	117	103
Asset retirement obligations	51	50
Debt, current portion	108	80
Total Current Liabilities	863	809
Debt, long-term portion	7,304	7,129
Liabilities from risk management activities	120	105
Asset retirement obligations	234	230
Deferred income taxes	44	29
Intangible liabilities	50	55
Other long-term liabilities	186	183
Total Liabilities	$ 8,801	$ 8,540
Commitments and Contingencies (Note 13)
Stockholders’ Equity
Common stock, $0.01 par value, 420,000,000 shares authorized; 128,566,819 shares issued and 117,240,697 shares outstanding at March 31, 2016; 128,228,477 shares issued and 116,902,355 outstanding at December 31, 2015	$ 1	$ 1
Additional paid-in capital	3,186	3,187
Accumulated other comprehensive income, net of tax	18	19
Accumulated deficit	(696)	(686)
Total Dynegy Stockholders’ Equity	2,909	2,921
Noncontrolling interest	(2)	(2)
Total Equity	2,907	2,919
Total Liabilities and Equity	11,708	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	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2014	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	128,566,819		128,228,477
Common stock, shares outstanding	117,240,697		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
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Revenues	$ 1,123	$ 632
Cost of sales, excluding depreciation expense	(545)	(377)
Gross margin	578	255
Operating and maintenance expense	(221)	(111)
Depreciation expense	(171)	(64)
General and administrative expense	(37)	(30)
Acquisition and integration costs	(4)	(90)
Operating income (loss)	145	(40)
Earnings from unconsolidated investments	2	0
Interest expense	(142)	(136)
Other income and (expense), net	1	(5)
Income (loss) before income taxes	6	(181)
Income tax expense (Note 14)	(16)	0
Net loss	(10)	(181)
Less: Net loss attributable to noncontrolling interest	0	(1)
Net loss attributable to Dynegy Inc.	(10)	(180)
Less: Dividends on preferred stock	5	5
Loss from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted loss per share	$ (15)	$ (185)
Loss Per Share (Note 17):
Basic and diluted loss per share attributable to Dynegy Inc. common stockholders (in dollars per share)	$ (0.13)	$ (1.49)
Basic and diluted shares outstanding (shares)	117	124

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (10)	$ (181)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively)	(1)	(1)
Other comprehensive loss, net of tax	(1)	(1)
Comprehensive loss	(11)	(182)
Less: Comprehensive loss attributable to noncontrolling interest	0	(1)
Total comprehensive loss attributable to Dynegy Inc.	$ (11)	$ (181)

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS (PARENTHETICAL) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Tax on actuarial loss	$ 0	$ 0
Tax on amortization of unrecognized prior service cost (credit) and actuarial loss (gain)	$ 0	$ 0

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Cash Flows [Abstract]
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	$ 8	$ 0
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	2	0
CASH FLOWS FROM OPERATING ACTIVITIES:
Net loss	(10)	(181)
Adjustments to reconcile net loss to net cash flows from operating activities:
Depreciation expense	171	64
Amortization of Financing Costs and Discounts	10	7
Amortization of intangibles	14	(4)
Unrealized gains (losses) relating to instruments held as of September 30, 2015	109	27
Deferred income taxes	16	0
Fair Value Adjustment of Warrants	(1)	5
Other	13	11
Changes in working capital:
Accounts receivable, net	65	1
Inventory	18	(18)
Prepayments and other current assets	28	(10)
Accounts payable and accrued liabilities	43	83
Changes in restricted cash	2	0
Changes in non-current assets	(70)	(4)
Changes in non-current liabilities	3	18
Net cash provided by (used in) operating activities	191	(55)
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures	65	40
Net cash used in investing activities	(57)	(40)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	198	0
Repayments of borrowings	(5)	(25)
Dividends paid	(5)	(7)
Interest rate swap settlement payments	(4)	(4)
Other financing	(2)	(5)
Net cash provided by (used in) financing activities	182	(41)
Net increase (decrease) in cash and cash equivalents	316	(136)
Cash and cash equivalents, beginning of period	505	1,870
Cash and cash equivalents, end of period	$ 821	$ 1,734

Basis of Presentation and Organ

Basis of Presentation and Organization	3 Months Ended
	Mar. 31, 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 19—Segment Information for further discussion. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents. Genco’s $825 million Senior Notes are non-recourse to Dynegy. Note 18—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. Dynegy Finance I, Inc. and Dynegy Finance II, Inc (the “Escrow Issuers”) were merged with Parent effective April 2015. Please read Note 13—Debt in our Form 10-K for further discussion These statements should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. For purposes of the unaudited condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of March 31, 2016 and December 31, 2015 . Condensed Consolidating Balance Sheet as of March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 639 $ 80 $ 102 $ — $ 821 Restricted cash — — 37 — 37 Accounts receivable, net 539 1,329 115 (1,644 ) 339 Inventory — 309 270 — 579 Other current assets 14 454 47 (10 ) 505 Total Current Assets 1,192 2,172 571 (1,654 ) 2,281 Property, plant and equipment, net — 7,722 520 — 8,242 Investment in affiliates 12,665 185 — (12,665 ) 185 Goodwill — 797 — — 797 Other assets 8 147 48 — 203 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 Current Liabilities Accounts payable $ 1,291 $ 202 $ 394 $ (1,644 ) $ 243 Other current liabilities 193 291 146 (10 ) 620 Total Current Liabilities 1,484 493 540 (1,654 ) 863 Debt, long-term portion 6,294 291 719 — 7,304 Intercompany note payable 3,042 — 17 (3,059 ) — Other liabilities 153 342 139 — 634 Total Liabilities 10,973 1,126 1,415 (4,713 ) 8,801 Stockholders’ Equity Dynegy Stockholders’ Equity 2,909 12,939 (274 ) (12,665 ) 2,909 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,909 9,897 (274 ) (9,623 ) 2,909 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,909 9,897 (276 ) (9,623 ) 2,907 Total Liabilities and Equity $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 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 Long-term debt 6,293 122 714 — 7,129 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 10,962 954 1,427 (4,803 ) 8,540 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459 Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 887 $ 236 $ — $ 1,123 Cost of sales, excluding depreciation expense — (412 ) (133 ) — (545 ) Gross margin — 475 103 — 578 Operating and maintenance expense — (159 ) (62 ) — (221 ) Depreciation expense — (146 ) (25 ) — (171 ) General and administrative expense (2 ) (28 ) (7 ) — (37 ) Acquisition and integration costs (3 ) (1 ) — — (4 ) Operating income (loss) (5 ) 141 9 — 145 Earnings from unconsolidated investments — 2 — — 2 Equity in earnings from investments in affiliates 118 — — (118 ) — Interest expense (124 ) (1 ) (17 ) — (142 ) Other income and expense, net 1 — — — 1 Income (loss) before income taxes (10 ) 142 (8 ) (118 ) 6 Income tax expense — (16 ) — — (16 ) Net income (loss) (10 ) 126 (8 ) (118 ) (10 ) Less: Net income attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ — $ 413 $ 219 $ — $ 632 Cost of sales, excluding depreciation expense — — (239 ) (138 ) — (377 ) Gross margin — — 174 81 — 255 Operating and maintenance expense — — (60 ) (51 ) — (111 ) Depreciation expense — — (56 ) (8 ) — (64 ) General and administrative expense (1 ) — (17 ) (12 ) — (30 ) Acquisition and integration costs — — — (90 ) — (90 ) Operating income (loss) (1 ) — 41 (80 ) — (40 ) Equity in losses from investments in affiliates (147 ) — — — 147 — Interest expense (27 ) (93 ) — (16 ) — (136 ) Other income and expense, net (5 ) — — — — (5 ) Income (loss) before income taxes (180 ) (93 ) 41 (96 ) 147 (181 ) Income tax expense — — — — — — Net income (loss) (180 ) (93 ) 41 (96 ) 147 (181 ) Less: Net loss attributable to noncontrolling interest — — — (1 ) — (1 ) Net income (loss) attributable to Dynegy Inc. $ (180 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (180 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — (1 ) Comprehensive income (loss) (11 ) 126 (8 ) (118 ) (11 ) Less: Comprehensive loss attributable to noncontrolling interest — — — — — Total comprehensive income (loss) attributable to Dynegy Inc. $ (11 ) $ 126 $ (8 ) $ (118 ) $ (11 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (180 ) $ (93 ) $ 41 $ (96 ) $ 147 $ (181 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — — (1 ) Comprehensive income (loss) (181 ) (93 ) 41 (96 ) 147 (182 ) Less: Comprehensive loss attributable to noncontrolling interest — — — (1 ) — (1 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ (181 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (181 ) Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (10 ) $ 175 $ 26 $ — $ 191 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (4 ) (50 ) (11 ) — (65 ) Net intercompany transfers 339 — — (339 ) — Distributions from unconsolidated affiliates — 8 — — 8 Net cash provided by (used in) investing activities 335 (42 ) (11 ) (339 ) (57 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowing on long term debt — 198 — — 198 Repayments of borrowings (2 ) (3 ) — — (5 ) Dividends paid (5 ) — — — (5 ) Net intercompany transfers — (342 ) 3 339 — Interest rate swap settlement payments (4 ) — — — (4 ) Other financing (2 ) — — — (2 ) Net cash provided by (used in) financing activities (13 ) (147 ) 3 339 182 Net increase (decrease) in cash and cash equivalents 312 (14 ) 18 — 316 Cash and cash equivalents, beginning of period 327 94 84 — 505 Cash and cash equivalents, end of period $ 639 $ 80 $ 102 $ — $ 821 Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ 2 $ (94 ) $ 46 $ (9 ) $ — $ (55 ) CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — — (29 ) (11 ) — (40 ) Net intercompany transfers (188 ) — — — 188 — Net cash provided by (used in) investing activities (188 ) — (29 ) (11 ) 188 (40 ) CASH FLOWS FROM FINANCING ACTIVITIES: Repayment of borrowings (2 ) — (23 ) — — (25 ) Dividends paid (7 ) — — — — (7 ) Net intercompany transfers — 94 74 20 (188 ) — Interest rate swap settlement payments (4 ) — — — — (4 ) Other financing (5 ) — — — — (5 ) Net cash provided by (used in) financing activities (18 ) 94 51 20 (188 ) (41 ) Net increase (decrease) in cash and cash equivalents (204 ) — 68 — — (136 ) Cash and cash equivalents, beginning of period 1,642 — 54 174 — 1,870 Cash and cash equivalents, end of period $ 1,438 $ — $ 122 $ 174 $ — $ 1,734

Accounting Policies

Accounting Policies	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Accounting Policies	Note 2—Accounting Policies Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors. The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. There have been no significant changes to our accounting policies during the three months ended March 31, 2016 . Accounting Standards Adopted During the Current Period Hybrid Financial Instruments. In November 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2014-16-Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in 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. Consolidation. In February 2015, the FASB issued ASU 2015-02-Consolidation (Topic 810). The amendments in this ASU respond to concerns about the current accounting for consolidation of certain legal entities, in particular: (i) consolidation of limited partnerships and similar legal entities, (ii) evaluating fees paid to a decision maker or a service provider as a variable interest, (iii) the effect of fee arrangements on the primary beneficiary determination, (iv) the effect of related parties on the primary beneficiary determination and (v) consolidation of certain investment funds. The 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 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 assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. 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 was further updated through the issuance of ASU 2015-14 in August 2015 and ASU 2016-08 in March 2016. The amendments in ASU 2015-14 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 amendments in ASU 2016-08 are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Acquisitions

Acquisitions	3 Months Ended
	Mar. 31, 2016
Business Combinations [Abstract]
Acquisitions	Note 3—Acquisitions Acquisitions Delta Stock Purchase Agreement. On February 24, 2016, Atlas Power Finance, LLC (“Atlas” or the “Purchaser”), a wholly owned subsidiary of Atlas Power, LLC (“Atlas Power” or the “JV”), a newly formed limited liability company that is 65 percent indirectly owned by Dynegy and 35 percent owned by affiliated investment funds of Energy Capital Partners III, LLC (the “ECP Funds”), entered into a Stock Purchase Agreement, as amended (the “Delta Stock Purchase Agreement”) with GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), indirect subsidiaries of Engie S.A. Pursuant to, and subject to the terms and conditions of, the Delta Stock Purchase Agreement, the Purchaser will purchase from the Seller 100 percent of the issued and outstanding shares of common stock of GSENA, thereby acquiring approximately 8,700 MW in certain power generation facilities located in ERCOT, PJM, and ISO-NE for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “Delta Transaction”). The Delta Stock Purchase Agreement includes customary representations, warranties and covenants by the parties. The Delta Transaction is subject to various closing conditions, including (i) expiration of the applicable waiting period, which was received on April 1, 2016, under the Hart-Scott-Rodino Act; (ii) obtaining required approvals from the FERC and the Public Utility Commission of Texas; (iii) no injunction or other orders preventing the consummation of the transactions contemplated under the Delta Stock Purchase Agreement; (iv) the completion of GSENA’s internal reorganization in all material respects in accordance with an exhibit attached to the Delta Stock Purchase Agreement; (v) the continuing accuracy of each party’s representations and warranties and (vi) the satisfaction of other customary conditions. We expect the Delta Transaction to close in the fourth quarter of 2016 after satisfaction or waiver of these closing conditions. Each party has agreed to indemnify the other for breaches of representations, warranties and covenants, and for certain other matters, subject to certain exceptions and limitations. The Delta Stock Purchase Agreement contains certain termination rights for both the Purchaser and the Seller, including if the closing does not occur within 12 months following the date of the Delta Stock Purchase Agreement. In the event the Delta Stock Purchase Agreement is terminated under certain circumstances, including the failure to obtain certain regulatory approvals, the Purchaser must pay GSENA a reverse termination fee of $132 million . In connection with the Delta Transaction, each of Dynegy and the ECP Funds entered into equity commitment letters with the JV and the Purchaser, pursuant to which Dynegy and the ECP Funds have agreed to provide up to $1.185 billion ( $770 million from Dynegy and $415 million from the ECP Funds) to the JV. Additionally, the JV has secured approximately $2.25 billion of committed debt facilities, including a $400 million junior bridge facility from the ECP funds and $1.85 billion of senior secured debt from a group of banks. These financings are non-recourse to Dynegy. We expect the JV to replace the $1.85 billion senior secured debt with permanent financing prior to the expected closing date of the Delta Transaction. Also, on February 24, 2016, Dynegy entered into a Stock Purchase Agreement (the “PIPE Stock Purchase Agreement”) with Terawatt Holdings, LP (“Terawatt”), an affiliate of ECP Funds, pursuant to which Dynegy will, subject to the terms and conditions of the PIPE Stock Purchase Agreement, sell and issue to Terawatt at the closing of the Delta Transaction 13,711,152 shares of common stock, $0.01 par value per share, of Dynegy for an aggregate purchase price equal to $150 million (the “PIPE Transaction”). The closing of the PIPE Transaction is contingent on the closing of the Delta Transaction. In addition, Dynegy has agreed to enter into an Investor Rights Agreement, in the form attached to the PIPE Stock Purchase Agreement (the “Investor Rights Agreement”), with Terawatt at the closing of the PIPE Transaction. Under the Investor Rights Agreement, Terawatt will be entitled to certain rights, including certain registration rights, rights of first refusal with respect to issuances of our common stock and the designation of one individual to serve on our Board of Directors as long as Terawatt and its affiliates own at least 10 percent of our common stock. Further, the Investor Rights Agreement subjects Terawatt to certain obligations, including certain voting obligations and customary standstill and lock-up periods. Concurrently with the execution of the Delta Stock Purchase Agreement, each of Dynegy and one of the ECP Funds entered into limited guarantees in favor of GSENA to guarantee 65 percent and 35 percent , respectively, of the Purchaser’s obligation to pay the reverse termination fee of $132 million in accordance with the terms and conditions of the Delta Stock Purchase Agreement. Please read Note 13—Commitments and Contingencies for further discussion. We incurred acquisition costs of $2 million for the three months ended March 31, 2016 related to the Delta Stock Purchase Agreement, which is included in Acquisition and integration costs in our unaudited consolidated statements of operations. Energy Capital Partners (“ECP”) Purchase Agreements. On April 1, 2015 (the “EquiPower Closing Date”), pursuant to the terms of a stock purchase agreement dated August 21, 2014, as amended, our wholly-owned subsidiary, Dynegy Resource II, LLC 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 Purchase Agreement. On April 2, 2015, pursuant to the terms of the purchase and sale agreement dated August 21, 2014, as amended (the “Duke Midwest Purchase Agreement”), our wholly-owned subsidiary Dynegy Resource I, LLC 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 levels. The initial accounting for the Acquisitions is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the second quarter of 2016. The significant assets and liabilities for which provisional amounts are recognized at the respective acquisition dates are property, plant and equipment (“PP&E”), goodwill, deferred income taxes and taxes other than deferred income taxes. We continue to evaluate settlements which could relate to pre-acquisition activity from the ISOs. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E, goodwill or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuation is completed, not to exceed one year, and any material adjustments identified that existed as of the acquisition date will be recognized in the current period. To fair value working capital, we used available market information. Asset retirement obligations (“AROs”) were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations. To fair value the acquired PP&E, we used a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model. 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. The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 126 175 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 22 10 32 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 506 — 506 Other long-term liabilities — 40 40 Total liabilities assumed 767 395 1,162 Identifiable net assets acquired 2,864 2,791 5,655 Goodwill 797 — 797 Net assets acquired $ 3,661 $ 2,791 $ 6,452 We incurred acquisition costs of zero and $90 million for the three months ended March 31, 2016 and 2015 , respectively, related to the Acquisitions, which are included in Acquisition and integration costs in our unaudited consolidated statements of operations. Acquisition costs for the three months ended March 31, 2015 included $42 million in acquisition advisory and consulting fees and $48 million in commitment fees associated with a temporary bridge facility, which were payable only upon the closing of the Acquisitions. No amounts were borrowed under the bridge facility, and the bridge facility was cancelled upon our execution of the permanent financing for the Acquisitions. Revenues of $661 million and operating income of $157 million attributable to the Acquisitions for the three months ended March 31, 2016 are included in our unaudited consolidated statements of operations. Pro Forma Results. The unaudited pro forma financial results for the three months ended March 31, 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 acquisition been completed as of January 1, 2014, nor are they indicative of future results of operations. (amounts in millions) Three Months Ended March 31, 2015 Revenues $ 1,622 Net income $ 80 Net loss attributable to noncontrolling interests $ (1 ) Net income attributable to Dynegy Inc. $ 81

Unconsolidated Investments

Unconsolidated Investments	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Unconsolidated Investments	Note 4—Unconsolidated Investments Equity Method Investments Elwood. In connection with the EquiPower Acquisition, we acquired a 50 percent interest in Elwood Energy LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (“Elwood Expansion” and, together with Elwood Energy, “Elwood”). Elwood Energy owns a 1,576 MW natural gas-fired facility located in Elwood, Illinois. At March 31, 2016 and December 31, 2015 , our equity method investment included in our unaudited consolidated balance sheets was $185 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; therefore, the debt of our unconsolidated investment is not reflected in our unaudited consolidated balance sheets. We recorded $2 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statement of operations for the three months ended March 31, 2016 . For the three months ended March 31, 2016 , we received a distribution of $8 million , all of which was considered a return of investment. At March 31, 2016 and December 31, 2015 , we have $2 million and $3 million in accounts receivable due from Elwood, respectively, which is included in Accounts receivable in our unaudited consolidated balance sheets. 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 are 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 March 31, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. March 31, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 205 $ (22 ) $ 3 $ 186 Stuart (1) 39.0 % $ 32 $ (5 ) $ 23 $ 50 Conesville (1) 40.0 % $ 60 $ (1 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (11 ) $ 10 $ 98 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy.

Risk Management Activities, Der

Risk Management Activities, Derivatives and Financial Instruments	3 Months Ended
	Mar. 31, 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 the unaudited consolidated statements of operations until the delivery occurs. Quantitative Disclosures Related to Financial Instruments and Derivatives As of March 31, 2016 , we had net purchases and sales of derivative contracts outstanding in the following quantities: Contract Type Quantity Unit of Measure Fair Value (1) (dollars and quantities in millions) Purchases (Sales) Asset (Liability) Commodity contracts: Electricity derivatives (2) (50 ) MWh $ 148 Electricity basis derivatives (3) (7 ) MWh $ 3 Natural gas derivatives (2) 362 MMBtu $ (168 ) Natural gas basis derivatives 83 MMBtu $ (3 ) Diesel fuel 2 Gallon $ (3 ) Coal derivatives (4) — Metric Ton $ (15 ) Emissions derivatives 4 Metric Ton $ (3 ) Interest rate swaps 775 U.S. Dollar $ (46 ) Common stock warrants (5) 16 Warrant $ (6 ) __________________________________________ (1) Includes both asset and liability risk management positions, but excludes margin and collateral netting of $79 million . (2) Mainly comprised of swaps, options, and physical forwards. (3) Comprised of FTRs and swaps. (4) Our net position rounds to less than 1 million tons. (5) Each warrant is convertible into one share of Dynegy common stock. 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 March 31, 2016 and December 31, 2015 . As of March 31, 2016 and December 31, 2015 , there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets. March 31, 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 $ 653 $ (424 ) $ — $ 229 Total derivative assets $ 653 $ (424 ) $ — $ 229 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (694 ) $ 424 $ 79 $ (191 ) Interest rate contracts Liabilities from risk management activities (46 ) — — (46 ) Common stock warrants Other long-term liabilities (6 ) — — (6 ) Total derivative liabilities $ (746 ) $ 424 $ 79 $ (243 ) Total derivatives $ (93 ) $ — $ 79 $ (14 ) 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 change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that are in a liability position that are not fully collateralized (excluding transactions with our clearing brokers that are fully collateralized) as of March 31, 2016 is $35 million for which we have posted $21 million in collateral. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program. The following table summarizes our cash collateral posted as of March 31, 2016 and December 31, 2015 , within Prepayments and other current assets on our unaudited consolidated balance sheets, and the amount applied against short-term risk management activities: Location on Balance Sheet March 31, 2016 December 31, 2015 (amounts in millions) Gross collateral posted with counterparties $ 140 $ 162 Less: Collateral netted against risk management liabilities 79 106 Net collateral within Prepayments and other current assets $ 61 $ 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 months ended March 31, 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 March 31, 2016 2015 (amounts in millions) Commodity contracts Revenues $ 192 $ 19 Interest rate contracts Interest expense $ (8 ) $ (9 ) Common stock warrants Other income and (expense), net $ 1 $ (5 )

Fair Value Measurements

Fair Value Measurements	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 2016 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 515 $ 47 $ 562 Natural gas derivatives — 67 14 81 Emissions derivatives — 1 — 1 Coal derivatives — 7 2 9 Total assets from commodity risk management activities $ — $ 590 $ 63 $ 653 Liabilities: . Liabilities from commodity risk management activities: Electricity derivatives $ — $ (347 ) $ (64 ) $ (411 ) Natural gas derivatives — (220 ) (32 ) (252 ) Emissions derivatives — (4 ) — (4 ) Diesel fuel derivatives — (3 ) — (3 ) Coal derivatives — (23 ) (1 ) (24 ) Total liabilities from commodity risk management activities — (597 ) (97 ) (694 ) Liabilities from interest rate contracts — (46 ) — (46 ) Liabilities from outstanding common stock warrants (6 ) — — (6 ) Total liabilities $ (6 ) $ (643 ) $ (97 ) $ (746 ) 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 March 31, 2016 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Input Significant Unobservable Input Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (4 ) Million MWh $ (12 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs 15 Million MWh $ (5 ) Historical congestion Forward price $0 - $9.00 Natural gas derivatives (1) 75 Million MMBtu $ (18 ) Illiquid location fixed price Forward price $1.20 - $1.50 Coal derivatives (1) — Thousand Tons $ 1 Illiquid location fixed price Forward price $4.20 - $5.10 __________________________________________ (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 March 31, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2015 $ (18 ) $ (32 ) $ 2 $ (48 ) Total gains included in earnings 8 5 — 13 Settlements (1) (7 ) 9 (1 ) 1 Balance at March 31, 2016 $ (17 ) $ (18 ) $ 1 $ (34 ) Unrealized gains relating to instruments held as of March 31, 2016 $ 8 $ 5 $ — $ 13 Three Months Ended March 31, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ (4 ) Total gains included in earnings 3 — — 3 Settlements (1) 5 — — 5 Balance at March 31, 2015 $ 4 $ — $ — $ 4 Unrealized gains relating to instruments held as of March 31, 2015 $ 3 $ — $ — $ 3 __________________________________________ (1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period. Gains and losses recognized for Level 3 recurring items are included in Revenues in our unaudited consolidated statements of operations for commodity derivatives. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. We did not have any transfers between Level 1, Level 2, and Level 3 for the three months ended March 31, 2016 and 2015 . Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. We did not have any material nonfinancial assets or liabilities measured at fair value on a non-recurring basis during the three months ended March 31, 2016 and 2015 , other than the provisional purchase price allocation discussed in Note 3—Acquisitions . Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments recognized on our unaudited consolidated balance sheets. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of March 31, 2016 and December 31, 2015 , respectively. March 31, 2016 December 31, 2015 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (1)(7) $ (2,078 ) $ (2,090 ) $ (2,077 ) $ (1,985 ) Tranche B-2 Term Loan, due 2020 (1)(2) $ (765 ) $ (766 ) $ (766 ) $ (754 ) 7.375% Senior Notes, due 2022 (1)(7) $ (1,729 ) $ (1,628 ) $ (1,729 ) $ (1,531 ) 5.875% Senior Notes, due 2023 (1)(7) $ (492 ) $ (423 ) $ (491 ) $ (404 ) 7.625% Senior Notes, due 2024 (1)(7) $ (1,235 ) $ (1,131 ) $ (1,235 ) $ (1,078 ) Forward capacity agreement (3)(8) $ (198 ) $ (198 ) $ — $ — Inventory financing agreements (8) $ (134 ) $ (134 ) $ (136 ) $ (136 ) Equipment financing agreements (4)(8) $ (62 ) $ (62 ) $ (61 ) $ (61 ) Interest rate derivatives (1) $ (46 ) $ (46 ) $ (42 ) $ (42 ) Commodity-based derivative contracts (5) $ (41 ) $ (41 ) $ (154 ) $ (154 ) Common stock warrants (6) $ (6 ) $ (6 ) $ (7 ) $ (7 ) Genco: 7.00% Senior Notes Series H, due 2018 (1)(9) $ (279 ) $ (120 ) $ (276 ) $ (204 ) 6.30% Senior Notes Series I, due 2020 (1)(9) $ (215 ) $ (85 ) $ (213 ) $ (148 ) 7.95% Senior Notes Series F, due 2032 (1)(9) $ (225 ) $ (88 ) $ (225 ) $ (162 ) __________________________________________ (1) The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels. (2) Carrying amount includes an unamortized discount and debt issuance costs of $13 million and $14 million as of March 31, 2016 and December 31, 2015 , respectively. Please read Note 12—Debt for further discussion. (3) Carrying amount includes an unamortized discount of $21 million as of March 31, 2016 . (4) Carrying amounts for the equipment financing agreement include unamortized discounts of $14 million and $14 million as of March 31, 2016 and December 31, 2015 , respectively. (5) Carrying amount of commodity-based derivative contracts excludes $79 million and $106 million of cash posted as collateral, as of March 31, 2016 and December 31, 2015 , respectively. (6) The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels. (7) Combined carrying amounts include debt issuance costs of $66 million and $68 million as of March 31, 2016 and December 31, 2015 , respectively. (8) The fair values of these financial instruments are classified as Level 3 within the fair value hierarchy levels and are based on internal estimates. (9) Combined carrying amounts include unamortized discounts and debt issuance costs of $106 million and $111 million as of March 31, 2016 and December 31, 2015 , respectively. Please read Note 12—Debt for further discussion.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	3 Months Ended
	Mar. 31, 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: Three Months Ended March 31, (amounts in millions) 2016 2015 Beginning of period $ 19 $ 20 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively) (1) (1 ) (1 ) Net current period other comprehensive loss, net of tax (1 ) (1 ) End of period $ 18 $ 19 __________________________________________ (1) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 15—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory

Inventory	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Inventory	Note 8—Inventory A summary of our inventories is as follows: (amounts in millions) March 31, 2016 December 31, 2015 Materials and supplies $ 176 $ 175 Coal (1) 344 350 Fuel oil (1) 17 17 Emissions allowances (2) 39 51 Other 3 4 Total $ 579 $ 597 __________________________________________ (1) At March 31, 2016 , approximately $46 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 12—Debt — Brayton Point Inventory Financing for further discussion. (2) At March 31, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 12—Debt — Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment

Property, Plant and Equipment	3 Months Ended
	Mar. 31, 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) March 31, 2016 December 31, 2015 Power generation $ 8,240 $ 8,178 Buildings and improvements 958 956 Office and other equipment 103 101 Property, plant and equipment 9,301 9,235 Accumulated depreciation (1,059 ) (888 ) Property, plant and equipment, net $ 8,242 $ 8,347

Joint Ownership of Generating F

Joint Ownership of Generating Facilities	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Joint Ownership of Generating Facilities	Note 4—Unconsolidated Investments Equity Method Investments Elwood. In connection with the EquiPower Acquisition, we acquired a 50 percent interest in Elwood Energy LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (“Elwood Expansion” and, together with Elwood Energy, “Elwood”). Elwood Energy owns a 1,576 MW natural gas-fired facility located in Elwood, Illinois. At March 31, 2016 and December 31, 2015 , our equity method investment included in our unaudited consolidated balance sheets was $185 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; therefore, the debt of our unconsolidated investment is not reflected in our unaudited consolidated balance sheets. We recorded $2 million in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statement of operations for the three months ended March 31, 2016 . For the three months ended March 31, 2016 , we received a distribution of $8 million , all of which was considered a return of investment. At March 31, 2016 and December 31, 2015 , we have $2 million and $3 million in accounts receivable due from Elwood, respectively, which is included in Accounts receivable in our unaudited consolidated balance sheets. 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 are 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 March 31, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. March 31, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 205 $ (22 ) $ 3 $ 186 Stuart (1) 39.0 % $ 32 $ (5 ) $ 23 $ 50 Conesville (1) 40.0 % $ 60 $ (1 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (11 ) $ 10 $ 98 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy.

Intangible Assets and Liabiliti

Intangible Assets and Liabilities	3 Months Ended
	Mar. 31, 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 March 31, 2016 and December 31, 2015: March 31, 2016 December 31, 2015 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (148 ) $ 112 $ 260 $ (126 ) $ 134 Gas transport contracts 46 (33 ) 13 46 (16 ) 30 Total intangible assets $ 306 $ (181 ) $ 125 $ 306 $ (142 ) $ 164 Intangible Liabilities: Electricity contracts $ (30 ) $ 25 $ (5 ) $ (30 ) $ 19 $ (11 ) Coal contracts (116 ) 76 (40 ) (134 ) 82 (52 ) Coal transport contracts (104 ) 71 (33 ) (104 ) 64 (40 ) Gas transport contracts (41 ) 4 (37 ) (64 ) 27 (37 ) Total intangible liabilities $ (291 ) $ 176 $ (115 ) $ (332 ) $ 192 $ (140 ) Intangible assets and liabilities, net $ 15 $ (5 ) $ 10 $ (26 ) $ 50 $ 24 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three months ended March 31, 2016 and 2015 : Three Months Ended March 31, (amounts in millions) 2016 2015 Electricity contracts, net (1) $ 16 $ 7 Coal contracts, net (2) (12 ) (3 ) Coal transport contracts, net (2) (7 ) (6 ) Gas transport contracts, net (2) 17 (2 ) Total $ 14 $ (4 ) __________________________________________ (1) The amortization of these contracts is recognized in Revenues in our unaudited consolidated statements of operations. (2) The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Debt

Debt	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Debt	Note 12—Debt A summary of our long-term debt is as follows: (amounts in millions) March 31, 2016 December 31, 2015 Dynegy Inc.: 6.75% Senior Notes, due 2019 $ 2,100 $ 2,100 Tranche B-2 Term Loan, due 2020 778 780 7.375% Senior Notes, due 2022 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 1,250 1,250 Forward Capacity Agreement 219 — Inventory Financing Agreements 134 136 Equipment Financing Agreements 76 75 Genco: 7.00% Senior Notes Series H, due 2018 300 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 7,632 7,416 Unamortized debt discounts and issuance costs (1) (220 ) (207 ) 7,412 7,209 Less: Current maturities, including unamortized debt discounts and issuance costs, net 108 80 Total Long-term debt $ 7,304 $ 7,129 __________________________________________ (1) Includes $ 80 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion. Senior Notes As of March 31, 2016, we had $ 5.6 billion in senior notes that consisted of (i) $ 2.1 billion 6.75 percent senior notes, due 2019, (ii) $1.75 billion 7.375 percent senior notes, due 2022, (iii) $500 million 5.875 percent senior notes, due 2023, and (iv) $1.25 billion 7.625 percent senior notes, due 2024 (collectively, the “Senior Notes”). Credit Agreement As of March 31, 2016 , we had a $2.225 billion credit agreement, as amended, that consisted of (i) an $800 million seven -year senior secured term loan B facility (the “Tranche B-2 Term Loan”) and (ii) $1.425 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche B-2 Term Loan, the “Credit Agreement”). The Revolving Facility includes three incremental tranches of revolving commitments consisting of: (i) a $475 million tranche which will mature on April 23, 2018, (ii) a $350 million tranche which will mature April 1, 2020, and (iii) a $600 million tranche which will mature on April 2, 2020. At March 31, 2016 , there were no amounts drawn on the Revolving Facility; however, we had outstanding letters of credit (“LCs”) of approximately $441 million , which reduce the amount available under the Revolving Facility. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Based on the calculation outlined in the Credit Agreement, we are in compliance as of March 31, 2016 . 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. The Genco Senior Notes are non-recourse to Dynegy. Genco’s indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates, or to incur additional external, third-party indebtedness. Genco’s debt incurrence-related ratio restrictions under the indenture may be disregarded if both Moody’s and S&P reaffirm the ratings in place at the time of the debt incurrence after considering the additional indebtedness. The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ≥1.75 Additional indebtedness interest coverage ratio (2) ≥2.50 Additional indebtedness debt-to-capital ratio (2) ≤60% __________________________________________ (1) As of the date of a restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods. (2) Ratios must be computed on a pro forma basis considering the additional indebtedness to be incurred and the related interest expense. Other borrowings from external, third-party sources are included in the definition of indebtedness and are subject to these incurrence tests. Based on March 31, 2016 calculations, Genco did not meet the ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources. Letter of Credit Facilities On January 29, 2014, Illinois Power Marketing Company (“IPM”) entered into a fully cash collateralized LC and Reimbursement Agreement with an issuing bank, as amended on May 16, 2014 (“LC Agreement”), pursuant to which the issuing bank agreed to issue from time to time, one or more standby LCs in an aggregate stated amount not to exceed $25 million at any one time to support performance obligations and other general corporate activities of IPM, provided that IPM deposits in an account controlled by the issuing bank an amount of cash sufficient to cover the face value of such requested LC plus an additional percentage thereon. As of March 31, 2016 , IPM had $14 million deposited with the issuing bank and $13 million in LCs outstanding. On September 18, 2014, Dynegy entered into an LC Reimbursement Agreement with an issuing bank, and its affiliate (the “Lender”), for an LC in an amount not to exceed $55 million . The facility expires in September 2016. At March 31, 2016 , there was $55 million outstanding under this LC. On March 27, 2015, IPM entered into an LC facility with the Lender for up to $25 million . The facility, which is collateralized by Illinois Power Resources Generating, LLC (“IPRG”) receivables, has a two -year tenor and may be extended if agreed to by both parties for one additional year. Interest on the facility is LIBOR plus 500 basis points on issued LCs. At March 31, 2016 , there was $22 million outstanding under this LC facility. Forward Capacity Agreement On March 18, 2016, we entered into a bilateral contract with a financial institution to sell a portion of our forward cleared PJM capacity auction volumes. In exchange, we received $ 198 million in cash proceeds during the first quarter of 2016. The buyer in this transaction will receive capacity payments from PJM during the Planning Years 2017-2018 and 2018-2019 in the amounts of $110 million and $109 million , respectively. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. The transaction is accounted for as a debt issuance of $219 million with an implied interest rate of 4.45 percent . Inventory Financing Agreements Brayton Point Inventory Financing. In connection with the EquiPower Acquisition, we assumed an inventory financing agreement (the “Inventory Financing Agreement”) for coal and fuel oil inventories at our Brayton Point facility, consisting of a debt obligation for existing and subsequent inventories, as well as a $15 million line of credit. Balances in excess of the $15 million line of credit are cash collateralized. The Inventory Financing Agreement terminates, and any remaining obligation becomes due and payable, on May 31, 2017. As of March 31, 2016 , there was $56 million outstanding under this agreement. Additionally, we had collateral postings of approximately $12 million . As the materials are purchased and delivered to our facilities, our debt obligation and line of credit increase based on the then market rate of the materials, transportation 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. Upon consuming the materials, we repay the debt obligation and line of credit at the then market price, as defined within the Inventory Financing Agreement, for the amount of the materials consumed on a weekly basis. As of March 31, 2016 , both the debt obligation related to coal and the base level of fuel oil, as well as the line of credit, bear interest at an annual interest rate of the 3 -month LIBOR plus 5.6 percent . An availability fee is calculated on a per annum rate of 0.75 percent . Emissions Repurchase Agreements. On August 14, 2015, we entered into a repurchase transaction with a third party in which we sold approximately $58 million of RGGI inventory and received cash. We are obligated to repurchase a portion of the inventory in February 2017 and the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.56 percent . On August 20, 2015, we entered into an additional repurchase transaction with a third party in which we sold $20 million of RGGI inventory and received cash. We are obligated to repurchase the additional RGGI inventory in February 2017 at a specified price with an annualized carry cost of approximately 3.31 percent . As of March 31, 2016 , there was $78 million , in aggregate, outstanding under these agreements. Equipment Financing Agreements Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to 2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our unaudited consolidated statements of cash flows. As of March 31, 2016 , there was $76 million outstanding under these agreements. The related assets were recorded at the net present value of the payments of $62 million . The $14 million discount is currently amortized as interest expense over the life of the payments. Interest Rate Swaps Subsequent to executing the Credit Agreement and issuing the Senior Notes, we amended our interest rate swaps to more closely match the terms of our Tranche B-2 Term Loan. The swaps have an aggregate notional value of approximately $775 million at an average fixed rate of 3.19 percent with a floor of one percent , and expire during the second quarter of 2020. In lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the new swaps are reflected as a financing activity in our unaudited consolidated statements of cash flows.

Commitments and Contingencies

Commitments and Contingencies	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Note 13—Commitments and Contingencies Legal Proceedings Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, 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 to IGC (not the $2.5 million in interest), but simultaneously appealed the judgment, which remains pending in the Dallas Court of Appeals. Other Contingencies MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. 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. If not overturned, this decision may provide an additional defense to the allegations in the Newton facility NOV. Wood River CAA Section 114 Information Request. In 2014, we received an information request from the EPA concerning our Wood River facility’s compliance with the Illinois State Implementation Plan (“SIP”) and associated permits. We responded to the EPA’s request and believe that there are no issues with Wood River’s compliance, but we are unable to predict the EPA’s response, if any. We plan to retire our Wood River facility on June 1, 2016, as approved by MISO. CAA Notices of Violation. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio SIP, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. In December 2014, the EPA also issued NOVs alleging violations of opacity standards at the Stuart and Killen facilities, which we co-own but do not operate. Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. The District Court has scheduled the trial date for October 2016. We dispute the allegations and will defend the case vigorously. Ultimate resolution of any of these CAA matters could have a material adverse impact on IPH’s future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters. Stuart NPDES Permit Appeal. In January 2013, the Ohio EPA reissued the National Pollutant Discharge Elimination System (“NPDES”) permit for the co-owned Stuart facility. The operator of Stuart, The Dayton Power and Light Company, appealed various aspects of the permit, including provisions regarding thermal discharge limitations, to the Ohio Environmental Review Appeals Commission. Depending on the outcome of the appeal, the effects on Stuart’s operations could be material. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve this matter. Coal Segment Groundwater . In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities. At Baldwin, with approval of the Illinois EPA, we performed a comprehensive evaluation of the Baldwin Coal Combustion Residuals (“CCR”) surface impoundment system beginning in 2013. Based on the results of that evaluation, we recommended to the Illinois EPA in 2014 that the closure process for the inactive east CCR surface impoundment begin and that a geotechnical investigation of the existing soil cap on the inactive old east CCR surface impoundment be undertaken. We also submitted a supplemental groundwater modeling report that indicates no known offsite water supply wells will be impacted under the various Baldwin CCR surface impoundment closure scenarios modeled. In April 2016, we submitted closure and post-closure care plans to the Illinois EPA for the Baldwin old east, east, and west fly ash CCR surface impoundments. We await Illinois EPA action on our plans. We initiated an investigation at Baldwin in 2011 at the request of the Illinois EPA to determine if the facility’s CCR surface impoundment system impacts offsite groundwater. Results of the offsite groundwater quality investigation, as submitted to the Illinois EPA in 2012, indicate two localized areas where Class I groundwater standards were exceeded. Based on the data and groundwater flows, we do not believe that the exceedances are attributable to the Baldwin CCR surface impoundment system. At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans for two CCR surface impoundments (i.e., the old east and the north CCR surface impoundments) to the Illinois EPA in 2012. Our hydrogeologic investigation indicates that these two CCR surface impoundments impact groundwater quality onsite and that such groundwater migrates offsite to the north of the property and to the adjacent Middle Fork of the Vermilion River. The proposed corrective action plans recommend closure in place of both CCR surface impoundments and include an application to the Illinois EPA to establish a groundwater management zone while impacts from the facility are mitigated. In 2014, we submitted a revised corrective action plan for the old east CCR surface impoundment. We await Illinois EPA action on our proposed corrective action plans. In June 2015, we advised the Illinois EPA that the additional analyses requested by the Agency would be performed upon receipt of a riverbank stabilization permit from the U.S. Army Corps of Engineers. Our estimated cost of the recommended closure alternative for both the Vermilion old east and north CCR surface impoundments, including post-closure care, is approximately $10 million . If remediation measures concerning groundwater are necessary in the future at either Baldwin or Vermilion, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. IPH Segment Groundwater. Groundwater monitoring results indicate that the CCR surface impoundments at each of the IPH segment facilities potentially impact onsite groundwater. In 2012, the Illinois EPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. In April 2015, we submitted an assessment monitoring report to the Illinois EPA concerning previously reported groundwater quality standard exceedances at the Newton facility’s active CCR landfill. The report identifies the Newton facility’s inactive unlined landfill as the likely source of the exceedances and recommends various measures to minimize the effects of that source on the groundwater monitoring results of the active landfill. If remediation measures concerning groundwater are necessary at any of our IPH facilities, IPH may incur significant costs that could have a material adverse effect on its financial condition, results of operations, and cash flows. At this time we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. Dam Safety Assessment Reports. In response to the failure at the Tennessee Valley Authority’s Kingston plant, the EPA initiated a nationwide investigation of the structural integrity of 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 Illinois EPA in 2014, and await Illinois EPA action. In response to the Baldwin report, we notified the EPA in 2013 of our action plan, which included implementation of recommended operating practices and certain recommended studies. In 2014, we updated the EPA on the status of our Baldwin action plan, including the completion of certain studies and implementation of remedial measures and our ongoing evaluation of potential long-term measures in the context of our concurrent evaluation at Baldwin of groundwater corrective actions. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in 2017, which is reflected in our AROs. Other Commitments In conducting our operations, we have routinely entered into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, design and construction, plant sites, and power generation assets. Indemnifications and Guarantees In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications, and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. We have accrued no amounts with respect to the indemnifications as of March 31, 2016 because none were probable of occurring, nor could they be reasonably estimated. Delta Transaction Guarantees. Concurrently with the execution of the Delta Transaction, each of Dynegy and one of the ECP Funds entered into limited guarantees in favor of GSENA to guarantee 65 percent and 35 percent , respectively, of the Purchaser’s obligation to pay the reverse termination fee of $132 million in accordance with the terms and conditions of the Delta Transaction.

Income Taxes

Income Taxes	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 14—Income Taxes We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant, unusual, or extraordinary transactions. Income taxes for significant, unusual, or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. Our Income tax expense for the three months ended March 31, 2016 includes a $15 million charge to deferred state income tax expense as a result of a change to our corporate tax structure in 2016. As of March 31, 2016 , we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future.

Pension and Other Post-Employme

Pension and Other Post-Employment Benefit Plans	3 Months Ended
	Mar. 31, 2016
Compensation and Retirement Disclosure [Abstract]
Pension and Other Post-Employment Benefit Plans	Note 15—Pension and Other Post-Employment Benefit Plans We sponsor and administer defined benefit plans and defined contribution plans for the benefit of our employees and also provide other post-employment benefits to retirees who meet age and service requirements, which are further described in Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K. 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 March 31, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 4 $ 3 $ — $ — Interest cost on projected benefit obligation 5 4 1 1 Expected return on plan assets (6 ) (5 ) (1 ) (1 ) Amortization of prior service credit — — (1 ) (1 ) Net periodic benefit cost (gain) $ 3 $ 2 $ (1 ) $ (1 )

Capital Stock

Capital Stock	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Capital Stock	Note 16—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 March 31, 2016 and 2015 , we paid an aggregate of $5 million and $7 million in dividends on February 1, 2016 and February 2, 2015, respectively. On April 1, 2016, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the dividend period beginning on February 1, 2016 and ending on April 30, 2016. Such dividends were paid on May 2, 2016 to stockholders of record as of April 15, 2016.

Loss Per Share

Loss Per Share	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Loss Per Share	Note 17—Loss Per Share The basic and diluted loss per share from continuing operations attributable to our common stockholders during the three months ended March 31, 2016 and 2015 is shown in the following table. Please read Note 15—Capital Stock in our Form 10-K for further discussion. Three Months Ended March 31, (in millions, except per share amounts) 2016 2015 Loss from continuing operations $ (10 ) $ (181 ) Less: Net loss attributable to noncontrolling interest — (1 ) Loss from continuing operations attributable to Dynegy Inc. (10 ) (180 ) Less: Dividends on preferred stock 5 5 Loss from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted loss per share (15 ) (185 ) Basic and diluted weighted-average shares (1) 117 124 Basic and diluted loss per share from continuing operations attributable to Dynegy Inc. common stockholders (1) $ (0.13 ) $ (1.49 ) __________________________________________ (1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2016 and 2015 . For the three months ended March 31, 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 March 31, (in millions of shares) 2016 2015 Stock options 2.8 1.8 Restricted stock units 1.3 1.2 Performance stock units 1.2 0.6 Warrants 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 12.9 Total 33.8 32.1

Condensed Consolidating Financi

Condensed Consolidating Financial Information	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Financial Information	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 19—Segment Information for further discussion. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents. Genco’s $825 million Senior Notes are non-recourse to Dynegy. Note 18—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. Dynegy Finance I, Inc. and Dynegy Finance II, Inc (the “Escrow Issuers”) were merged with Parent effective April 2015. Please read Note 13—Debt in our Form 10-K for further discussion These statements should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. For purposes of the unaudited condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of March 31, 2016 and December 31, 2015 . Condensed Consolidating Balance Sheet as of March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 639 $ 80 $ 102 $ — $ 821 Restricted cash — — 37 — 37 Accounts receivable, net 539 1,329 115 (1,644 ) 339 Inventory — 309 270 — 579 Other current assets 14 454 47 (10 ) 505 Total Current Assets 1,192 2,172 571 (1,654 ) 2,281 Property, plant and equipment, net — 7,722 520 — 8,242 Investment in affiliates 12,665 185 — (12,665 ) 185 Goodwill — 797 — — 797 Other assets 8 147 48 — 203 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 Current Liabilities Accounts payable $ 1,291 $ 202 $ 394 $ (1,644 ) $ 243 Other current liabilities 193 291 146 (10 ) 620 Total Current Liabilities 1,484 493 540 (1,654 ) 863 Debt, long-term portion 6,294 291 719 — 7,304 Intercompany note payable 3,042 — 17 (3,059 ) — Other liabilities 153 342 139 — 634 Total Liabilities 10,973 1,126 1,415 (4,713 ) 8,801 Stockholders’ Equity Dynegy Stockholders’ Equity 2,909 12,939 (274 ) (12,665 ) 2,909 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,909 9,897 (274 ) (9,623 ) 2,909 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,909 9,897 (276 ) (9,623 ) 2,907 Total Liabilities and Equity $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 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 Long-term debt 6,293 122 714 — 7,129 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 10,962 954 1,427 (4,803 ) 8,540 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459 Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 887 $ 236 $ — $ 1,123 Cost of sales, excluding depreciation expense — (412 ) (133 ) — (545 ) Gross margin — 475 103 — 578 Operating and maintenance expense — (159 ) (62 ) — (221 ) Depreciation expense — (146 ) (25 ) — (171 ) General and administrative expense (2 ) (28 ) (7 ) — (37 ) Acquisition and integration costs (3 ) (1 ) — — (4 ) Operating income (loss) (5 ) 141 9 — 145 Earnings from unconsolidated investments — 2 — — 2 Equity in earnings from investments in affiliates 118 — — (118 ) — Interest expense (124 ) (1 ) (17 ) — (142 ) Other income and expense, net 1 — — — 1 Income (loss) before income taxes (10 ) 142 (8 ) (118 ) 6 Income tax expense — (16 ) — — (16 ) Net income (loss) (10 ) 126 (8 ) (118 ) (10 ) Less: Net income attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ — $ 413 $ 219 $ — $ 632 Cost of sales, excluding depreciation expense — — (239 ) (138 ) — (377 ) Gross margin — — 174 81 — 255 Operating and maintenance expense — — (60 ) (51 ) — (111 ) Depreciation expense — — (56 ) (8 ) — (64 ) General and administrative expense (1 ) — (17 ) (12 ) — (30 ) Acquisition and integration costs — — — (90 ) — (90 ) Operating income (loss) (1 ) — 41 (80 ) — (40 ) Equity in losses from investments in affiliates (147 ) — — — 147 — Interest expense (27 ) (93 ) — (16 ) — (136 ) Other income and expense, net (5 ) — — — — (5 ) Income (loss) before income taxes (180 ) (93 ) 41 (96 ) 147 (181 ) Income tax expense — — — — — — Net income (loss) (180 ) (93 ) 41 (96 ) 147 (181 ) Less: Net loss attributable to noncontrolling interest — — — (1 ) — (1 ) Net income (loss) attributable to Dynegy Inc. $ (180 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (180 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — (1 ) Comprehensive income (loss) (11 ) 126 (8 ) (118 ) (11 ) Less: Comprehensive loss attributable to noncontrolling interest — — — — — Total comprehensive income (loss) attributable to Dynegy Inc. $ (11 ) $ 126 $ (8 ) $ (118 ) $ (11 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (180 ) $ (93 ) $ 41 $ (96 ) $ 147 $ (181 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — — (1 ) Comprehensive income (loss) (181 ) (93 ) 41 (96 ) 147 (182 ) Less: Comprehensive loss attributable to noncontrolling interest — — — (1 ) — (1 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ (181 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (181 ) Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (10 ) $ 175 $ 26 $ — $ 191 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (4 ) (50 ) (11 ) — (65 ) Net intercompany transfers 339 — — (339 ) — Distributions from unconsolidated affiliates — 8 — — 8 Net cash provided by (used in) investing activities 335 (42 ) (11 ) (339 ) (57 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowing on long term debt — 198 — — 198 Repayments of borrowings (2 ) (3 ) — — (5 ) Dividends paid (5 ) — — — (5 ) Net intercompany transfers — (342 ) 3 339 — Interest rate swap settlement payments (4 ) — — — (4 ) Other financing (2 ) — — — (2 ) Net cash provided by (used in) financing activities (13 ) (147 ) 3 339 182 Net increase (decrease) in cash and cash equivalents 312 (14 ) 18 — 316 Cash and cash equivalents, beginning of period 327 94 84 — 505 Cash and cash equivalents, end of period $ 639 $ 80 $ 102 $ — $ 821 Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ 2 $ (94 ) $ 46 $ (9 ) $ — $ (55 ) CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — — (29 ) (11 ) — (40 ) Net intercompany transfers (188 ) — — — 188 — Net cash provided by (used in) investing activities (188 ) — (29 ) (11 ) 188 (40 ) CASH FLOWS FROM FINANCING ACTIVITIES: Repayment of borrowings (2 ) — (23 ) — — (25 ) Dividends paid (7 ) — — — — (7 ) Net intercompany transfers — 94 74 20 (188 ) — Interest rate swap settlement payments (4 ) — — — — (4 ) Other financing (5 ) — — — — (5 ) Net cash provided by (used in) financing activities (18 ) 94 51 20 (188 ) (41 ) Net increase (decrease) in cash and cash equivalents (204 ) — 68 — — (136 ) Cash and cash equivalents, beginning of period 1,642 — 54 174 — 1,870 Cash and cash equivalents, end of period $ 1,438 $ — $ 122 $ 174 $ — $ 1,734

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2016
Segment Reporting [Abstract]
Segment Information	Note 19—Segment Information We report the results of our operations in three segments: (i) Coal, (ii) IPH, and (iii) Gas. The Coal segment includes certain of our coal-fired power generation facilities and our Dynegy Energy Services retail business. The IPH segment includes Genco, and 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 months ended March 31, 2016 and 2015 is presented below: Segment Data as of and for the Three Months Ended March 31, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 393 $ 168 $ 562 $ — $ 1,123 Intercompany revenues (13 ) (1 ) 14 — — Total revenues $ 380 $ 167 $ 576 $ — $ 1,123 Depreciation expense $ (39 ) $ (9 ) $ (122 ) $ (1 ) $ (171 ) General and administrative expense — — — (37 ) (37 ) Acquisition and integration costs — — — (4 ) (4 ) Operating income (loss) $ 54 $ 14 $ 120 $ (43 ) $ 145 Earnings from unconsolidated investments — — 2 — 2 Interest expense (1 ) (17 ) (1 ) (123 ) (142 ) Other income and expense, net — — — 1 1 Income before income taxes 6 Income tax expense — — — (16 ) (16 ) Net loss (10 ) Less: Net loss attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (10 ) Total assets—domestic $ 2,269 $ 898 $ 7,815 $ 726 $ 11,708 Investment in unconsolidated affiliate $ — $ — $ 185 $ — $ 185 Capital expenditures $ (19 ) $ (11 ) $ (31 ) $ (4 ) $ (65 ) Segment Data as of and for the Three Months Ended March 31, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 154 $ 219 $ 259 $ — $ 632 Intercompany revenues (12 ) — 12 — — Total revenues $ 142 $ 219 $ 271 $ — $ 632 Depreciation expense $ (10 ) $ (8 ) $ (45 ) $ (1 ) $ (64 ) General and administrative expense — — — (30 ) (30 ) Operating income (loss) $ 7 $ 22 $ 52 $ (121 ) $ (40 ) Interest expense — — — (136 ) (136 ) Other income and expense, net — — — (5 ) (5 ) Loss before income taxes (181 ) Income tax expense — — — — — Net loss (181 ) Less: Net loss attributable to noncontrolling interest (1 ) Net loss attributable to Dynegy Inc. $ (180 ) Total assets—domestic $ 1,162 $ 1,037 $ 2,105 $ 6,827 $ 11,131 Capital expenditures $ (3 ) $ (11 ) $ (24 ) $ (2 ) $ (40 )

Subsequent Event Subsequent Eve

Subsequent Event Subsequent Event	3 Months Ended
	Mar. 31, 2016
Subsequent Event [Abstract]
Subsequent Event	Note 20—Subsequent Event On May 3, 2016, Dynegy announced the shutdown of two of the three units at its Baldwin power generation facility in Baldwin, Illinois and one of the two units at its Newton power generation facility in Newton, Illinois. Subject to the approval of MISO, we expect to shut down the units over the next year. This decision was made after the units failed to recover their basic operating costs in the most recent MISO auction. Factors influencing these actions included a low power pricing environment, a lack of capacity revenue, and significant maintenance and environmental expenditures required to appropriately maintain the facilities. We will assess the carrying value of our entire MISO fleet for impairment during the second quarter of 2016. As of March 31, 2016, our MISO facilities had a combined carrying value of $1.4 billion .

Accounting Policies (Policies)

Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 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 19—Segment Information for further discussion. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and its other subsidiaries. Certain of the entities in the IPH segment, including Illinois Power Generating Company (“Genco”), have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents.
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. The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with accounting principles generally accepted in the United States of America. There have been no significant changes to our accounting policies during the three months ended March 31, 2016 .
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. Consolidation. In February 2015, the FASB issued ASU 2015-02-Consolidation (Topic 810). The amendments in this ASU respond to concerns about the current accounting for consolidation of certain legal entities, in particular: (i) consolidation of limited partnerships and similar legal entities, (ii) evaluating fees paid to a decision maker or a service provider as a variable interest, (iii) the effect of fee arrangements on the primary beneficiary determination, (iv) the effect of related parties on the primary beneficiary determination and (v) consolidation of certain investment funds. The 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 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 assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The amendments in this ASU will mainly require lessees to recognize lease assets and lease liabilities, for those leases classified as operating leases under GAAP, in their balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured on a discounted basis. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption of this ASU will have on our unaudited consolidated financial statements. 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 was further updated through the issuance of ASU 2015-14 in August 2015 and ASU 2016-08 in March 2016. The amendments in ASU 2015-14 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 amendments in ASU 2016-08 are intended to improve the operability and understandability of the implementation guidance on principal versus agent considerations. The guidance in this ASU is effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We are currently assessing this ASU; however, we do not anticipate the adoption of this ASU will have a material impact on our unaudited consolidated financial statements.

Acquisitions (Tables)

Acquisitions (Tables)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Business Combinations [Abstract]
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the EquiPower Acquisition and Duke Midwest Acquisition, as of the respective acquisition dates, April 1, 2015 and April 2, 2015: (amounts in millions) EquiPower Acquisition Duke Midwest Acquisition Total Cash $ 3,350 $ 2,800 $ 6,150 Equity instruments (3,460,053 common shares of Dynegy) 105 — 105 Net working capital adjustment 206 (9 ) 197 Fair value of total consideration transferred $ 3,661 $ 2,791 $ 6,452 Cash $ 267 $ — $ 267 Accounts receivable 49 126 175 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 22 10 32 Debt, current portion 39 — 39 Liabilities from risk management activities (including current portion of $41 million and zero, respectively) 57 107 164 Asset retirement obligations 43 49 92 Intangible liabilities (including current portion of $24 million and $58 million, respectively) 73 93 166 Deferred income taxes, net 506 — 506 Other long-term liabilities — 40 40 Total liabilities assumed 767 395 1,162 Identifiable net assets acquired 2,864 2,791 5,655 Goodwill 797 — 797 Net assets acquired $ 3,661 $ 2,791 $ 6,452
Business Acquisition, Pro Forma Information		The unaudited pro forma financial results for the three months ended March 31, 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 acquisition been completed as of January 1, 2014, nor are they indicative of future results of operations. (amounts in millions) Three Months Ended March 31, 2015 Revenues $ 1,622 Net income $ 80 Net loss attributable to noncontrolling interests $ (1 ) Net income attributable to Dynegy Inc. $ 81

Risk Management Activities, D30

Risk Management Activities, Derivatives and Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Contracts and Interest Rate Swaps	As of March 31, 2016 , we had net purchases and sales of derivative contracts outstanding in the following quantities: Contract Type Quantity Unit of Measure Fair Value (1) (dollars and quantities in millions) Purchases (Sales) Asset (Liability) Commodity contracts: Electricity derivatives (2) (50 ) MWh $ 148 Electricity basis derivatives (3) (7 ) MWh $ 3 Natural gas derivatives (2) 362 MMBtu $ (168 ) Natural gas basis derivatives 83 MMBtu $ (3 ) Diesel fuel 2 Gallon $ (3 ) Coal derivatives (4) — Metric Ton $ (15 ) Emissions derivatives 4 Metric Ton $ (3 ) Interest rate swaps 775 U.S. Dollar $ (46 ) Common stock warrants (5) 16 Warrant $ (6 ) __________________________________________ (1) Includes both asset and liability risk management positions, but excludes margin and collateral netting of $79 million . (2) Mainly comprised of swaps, options, and physical forwards. (3) Comprised of FTRs and swaps. (4) Our net position rounds to less than 1 million tons. (5) Each warrant is convertible into one share of Dynegy common stock.
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 March 31, 2016 and December 31, 2015 . As of March 31, 2016 and December 31, 2015 , there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets. March 31, 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 $ 653 $ (424 ) $ — $ 229 Total derivative assets $ 653 $ (424 ) $ — $ 229 Derivative liabilities: Commodity contracts Liabilities from risk management activities $ (694 ) $ 424 $ 79 $ (191 ) Interest rate contracts Liabilities from risk management activities (46 ) — — (46 ) Common stock warrants Other long-term liabilities (6 ) — — (6 ) Total derivative liabilities $ (746 ) $ 424 $ 79 $ (243 ) Total derivatives $ (93 ) $ — $ 79 $ (14 ) 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 March 31, 2016 and December 31, 2015 , within Prepayments and other current assets on our unaudited consolidated balance sheets, and the amount applied against short-term risk management activities: Location on Balance Sheet March 31, 2016 December 31, 2015 (amounts in millions) Gross collateral posted with counterparties $ 140 $ 162 Less: Collateral netted against risk management liabilities 79 106 Net collateral within Prepayments and other current assets $ 61 $ 56
Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations	Our unaudited consolidated statements of operations for the three months ended March 31, 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 March 31, 2016 2015 (amounts in millions) Commodity contracts Revenues $ 192 $ 19 Interest rate contracts Interest expense $ (8 ) $ (9 ) Common stock warrants Other income and (expense), net $ 1 $ (5 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 2016 (amounts in millions) Level 1 Level 2 Level 3 Total Assets: Assets from commodity risk management activities: Electricity derivatives $ — $ 515 $ 47 $ 562 Natural gas derivatives — 67 14 81 Emissions derivatives — 1 — 1 Coal derivatives — 7 2 9 Total assets from commodity risk management activities $ — $ 590 $ 63 $ 653 Liabilities: . Liabilities from commodity risk management activities: Electricity derivatives $ — $ (347 ) $ (64 ) $ (411 ) Natural gas derivatives — (220 ) (32 ) (252 ) Emissions derivatives — (4 ) — (4 ) Diesel fuel derivatives — (3 ) — (3 ) Coal derivatives — (23 ) (1 ) (24 ) Total liabilities from commodity risk management activities — (597 ) (97 ) (694 ) Liabilities from interest rate contracts — (46 ) — (46 ) Liabilities from outstanding common stock warrants (6 ) — — (6 ) Total liabilities $ (6 ) $ (643 ) $ (97 ) $ (746 ) 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 March 31, 2016 are as follows: Transaction Type Quantity Unit of Measure Net Fair Value Valuation Technique Significant Unobservable Input Significant Unobservable Input Range (dollars in millions) Electricity derivatives: Forward contracts—power (1) (4 ) Million MWh $ (12 ) Basis spread + liquid location Basis spread $5.00 - $7.00 FTRs 15 Million MWh $ (5 ) Historical congestion Forward price $0 - $9.00 Natural gas derivatives (1) 75 Million MMBtu $ (18 ) Illiquid location fixed price Forward price $1.20 - $1.50 Coal derivatives (1) — Thousand Tons $ 1 Illiquid location fixed price Forward price $4.20 - $5.10 __________________________________________ (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 March 31, 2016 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2015 $ (18 ) $ (32 ) $ 2 $ (48 ) Total gains included in earnings 8 5 — 13 Settlements (1) (7 ) 9 (1 ) 1 Balance at March 31, 2016 $ (17 ) $ (18 ) $ 1 $ (34 ) Unrealized gains relating to instruments held as of March 31, 2016 $ 8 $ 5 $ — $ 13 Three Months Ended March 31, 2015 (amounts in millions) Electricity Derivatives Natural Gas Derivatives Coal Derivatives Total Balance at December 31, 2014 $ (4 ) $ — $ — $ (4 ) Total gains included in earnings 3 — — 3 Settlements (1) 5 — — 5 Balance at March 31, 2015 $ 4 $ — $ — $ 4 Unrealized gains relating to instruments held as of March 31, 2015 $ 3 $ — $ — $ 3 __________________________________________ (1) For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.
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 March 31, 2016 and December 31, 2015 , respectively. March 31, 2016 December 31, 2015 (amounts in millions) Carrying Amount Fair Value Carrying Amount Fair Value Dynegy Inc.: 6.75% Senior Notes, due 2019 (1)(7) $ (2,078 ) $ (2,090 ) $ (2,077 ) $ (1,985 ) Tranche B-2 Term Loan, due 2020 (1)(2) $ (765 ) $ (766 ) $ (766 ) $ (754 ) 7.375% Senior Notes, due 2022 (1)(7) $ (1,729 ) $ (1,628 ) $ (1,729 ) $ (1,531 ) 5.875% Senior Notes, due 2023 (1)(7) $ (492 ) $ (423 ) $ (491 ) $ (404 ) 7.625% Senior Notes, due 2024 (1)(7) $ (1,235 ) $ (1,131 ) $ (1,235 ) $ (1,078 ) Forward capacity agreement (3)(8) $ (198 ) $ (198 ) $ — $ — Inventory financing agreements (8) $ (134 ) $ (134 ) $ (136 ) $ (136 ) Equipment financing agreements (4)(8) $ (62 ) $ (62 ) $ (61 ) $ (61 ) Interest rate derivatives (1) $ (46 ) $ (46 ) $ (42 ) $ (42 ) Commodity-based derivative contracts (5) $ (41 ) $ (41 ) $ (154 ) $ (154 ) Common stock warrants (6) $ (6 ) $ (6 ) $ (7 ) $ (7 ) Genco: 7.00% Senior Notes Series H, due 2018 (1)(9) $ (279 ) $ (120 ) $ (276 ) $ (204 ) 6.30% Senior Notes Series I, due 2020 (1)(9) $ (215 ) $ (85 ) $ (213 ) $ (148 ) 7.95% Senior Notes Series F, due 2032 (1)(9) $ (225 ) $ (88 ) $ (225 ) $ (162 ) __________________________________________ (1) The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels. (2) Carrying amount includes an unamortized discount and debt issuance costs of $13 million and $14 million as of March 31, 2016 and December 31, 2015 , respectively. Please read Note 12—Debt for further discussion. (3) Carrying amount includes an unamortized discount of $21 million as of March 31, 2016 . (4) Carrying amounts for the equipment financing agreement include unamortized discounts of $14 million and $14 million as of March 31, 2016 and December 31, 2015 , respectively. (5) Carrying amount of commodity-based derivative contracts excludes $79 million and $106 million of cash posted as collateral, as of March 31, 2016 and December 31, 2015 , respectively. (6) The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels. (7) Combined carrying amounts include debt issuance costs of $66 million and $68 million as of March 31, 2016 and December 31, 2015 , respectively. (8) The fair values of these financial instruments are classified as Level 3 within the fair value hierarchy levels and are based on internal estimates. (9) Combined carrying amounts include unamortized discounts and debt issuance costs of $106 million and $111 million as of March 31, 2016 and December 31, 2015 , respectively. Please read Note 12—Debt for further discussion.

Accumulated Other Comprehensi32

Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 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: Three Months Ended March 31, (amounts in millions) 2016 2015 Beginning of period $ 19 $ 20 Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively) (1) (1 ) (1 ) Net current period other comprehensive loss, net of tax (1 ) (1 ) End of period $ 18 $ 19 __________________________________________ (1) Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 15—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory (Tables)

Inventory (Tables)	3 Months Ended
	Mar. 31, 2016
Inventory Disclosure [Abstract]
Summary of Inventories	A summary of our inventories is as follows: (amounts in millions) March 31, 2016 December 31, 2015 Materials and supplies $ 176 $ 175 Coal (1) 344 350 Fuel oil (1) 17 17 Emissions allowances (2) 39 51 Other 3 4 Total $ 579 $ 597 __________________________________________ (1) At March 31, 2016 , approximately $46 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 12—Debt — Brayton Point Inventory Financing for further discussion. (2) At March 31, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 12—Debt — Emissions Repurchase Agreements for further discussion.

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	A summary of our property, plant and equipment is as follows: (amounts in millions) March 31, 2016 December 31, 2015 Power generation $ 8,240 $ 8,178 Buildings and improvements 958 956 Office and other equipment 103 101 Property, plant and equipment 9,301 9,235 Accumulated depreciation (1,059 ) (888 ) Property, plant and equipment, net $ 8,242 $ 8,347

Joint Ownership of Generating35

Joint Ownership of Generating Facilities (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016 and December 31, 2015 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies. March 31, 2016 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 205 $ (22 ) $ 3 $ 186 Stuart (1) 39.0 % $ 32 $ (5 ) $ 23 $ 50 Conesville (1) 40.0 % $ 60 $ (1 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (11 ) $ 10 $ 98 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 December 31, 2015 (dollars in millions) Ownership Interest Property, Plant and Equipment Accumulated Depreciation Construction Work in Progress Total Miami Fort 64.0 % $ 207 $ (16 ) $ 3 $ 194 Stuart (1) 39.0 % $ 32 $ (4 ) $ 20 $ 48 Conesville (1) 40.0 % $ 61 $ (2 ) $ 4 $ 63 Zimmer 46.5 % $ 99 $ (10 ) $ 11 $ 100 Killen (1) 33.0 % $ 17 $ (1 ) $ 2 $ 18 __________________________________________ (1) Facilities not operated by Dynegy.

Intangible Assets and Liabili36

Intangible Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2016 and December 31, 2015: March 31, 2016 December 31, 2015 (amounts in millions) Gross Carrying Amount Accumulated Amortization Net Carrying Amount Gross Carrying Amount Accumulated Amortization Net Carrying Amount Intangible Assets: Electricity contracts $ 260 $ (148 ) $ 112 $ 260 $ (126 ) $ 134 Gas transport contracts 46 (33 ) 13 46 (16 ) 30 Total intangible assets $ 306 $ (181 ) $ 125 $ 306 $ (142 ) $ 164 Intangible Liabilities: Electricity contracts $ (30 ) $ 25 $ (5 ) $ (30 ) $ 19 $ (11 ) Coal contracts (116 ) 76 (40 ) (134 ) 82 (52 ) Coal transport contracts (104 ) 71 (33 ) (104 ) 64 (40 ) Gas transport contracts (41 ) 4 (37 ) (64 ) 27 (37 ) Total intangible liabilities $ (291 ) $ 176 $ (115 ) $ (332 ) $ 192 $ (140 ) Intangible assets and liabilities, net $ 15 $ (5 ) $ 10 $ (26 ) $ 50 $ 24 The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three months ended March 31, 2016 and 2015 : Three Months Ended March 31, (amounts in millions) 2016 2015 Electricity contracts, net (1) $ 16 $ 7 Coal contracts, net (2) (12 ) (3 ) Coal transport contracts, net (2) (7 ) (6 ) Gas transport contracts, net (2) 17 (2 ) Total $ 14 $ (4 ) __________________________________________ (1) The amortization of these contracts is recognized in Revenues in our unaudited consolidated statements of operations. (2) The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations.

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt Instruments	A summary of our long-term debt is as follows: (amounts in millions) March 31, 2016 December 31, 2015 Dynegy Inc.: 6.75% Senior Notes, due 2019 $ 2,100 $ 2,100 Tranche B-2 Term Loan, due 2020 778 780 7.375% Senior Notes, due 2022 1,750 1,750 5.875% Senior Notes, due 2023 500 500 7.625% Senior Notes, due 2024 1,250 1,250 Forward Capacity Agreement 219 — Inventory Financing Agreements 134 136 Equipment Financing Agreements 76 75 Genco: 7.00% Senior Notes Series H, due 2018 300 300 6.30% Senior Notes Series I, due 2020 250 250 7.95% Senior Notes Series F, due 2032 275 275 7,632 7,416 Unamortized debt discounts and issuance costs (1) (220 ) (207 ) 7,412 7,209 Less: Current maturities, including unamortized debt discounts and issuance costs, net 108 80 Total Long-term debt $ 7,304 $ 7,129 __________________________________________ (1) Includes $ 80 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion.
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-Employ38

Pension and Other Post-Employment Benefit Plans (Tables)	3 Months Ended
	Mar. 31, 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 March 31, (amounts in millions) 2016 2015 2016 2015 Service cost benefits earned during period $ 4 $ 3 $ — $ — Interest cost on projected benefit obligation 5 4 1 1 Expected return on plan assets (6 ) (5 ) (1 ) (1 ) Amortization of prior service credit — — (1 ) (1 ) Net periodic benefit cost (gain) $ 3 $ 2 $ (1 ) $ (1 )

Loss Per Share (Tables)

Loss Per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings (Loss) Per Share, Basic and Diluted	The basic and diluted loss per share from continuing operations attributable to our common stockholders during the three months ended March 31, 2016 and 2015 is shown in the following table. Please read Note 15—Capital Stock in our Form 10-K for further discussion. Three Months Ended March 31, (in millions, except per share amounts) 2016 2015 Loss from continuing operations $ (10 ) $ (181 ) Less: Net loss attributable to noncontrolling interest — (1 ) Loss from continuing operations attributable to Dynegy Inc. (10 ) (180 ) Less: Dividends on preferred stock 5 5 Loss from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted loss per share (15 ) (185 ) Basic and diluted weighted-average shares (1) 117 124 Basic and diluted loss per share from continuing operations attributable to Dynegy Inc. common stockholders (1) $ (0.13 ) $ (1.49 ) __________________________________________ (1) Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have used the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended March 31, 2016 and 2015 .
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	For the three months ended March 31, 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 March 31, (in millions of shares) 2016 2015 Stock options 2.8 1.8 Restricted stock units 1.3 1.2 Performance stock units 1.2 0.6 Warrants 15.6 15.6 Series A 5.375% mandatory convertible preferred stock 12.9 12.9 Total 33.8 32.1

Condensed Consolidating Finan40

Condensed Consolidating Financial Information (Tables)	3 Months Ended
	Mar. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Condensed Consolidating Balance Sheets	Condensed Consolidating Balance Sheet as of March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Current Assets Cash and cash equivalents $ 639 $ 80 $ 102 $ — $ 821 Restricted cash — — 37 — 37 Accounts receivable, net 539 1,329 115 (1,644 ) 339 Inventory — 309 270 — 579 Other current assets 14 454 47 (10 ) 505 Total Current Assets 1,192 2,172 571 (1,654 ) 2,281 Property, plant and equipment, net — 7,722 520 — 8,242 Investment in affiliates 12,665 185 — (12,665 ) 185 Goodwill — 797 — — 797 Other assets 8 147 48 — 203 Intercompany note receivable 17 — — (17 ) — Total Assets $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 Current Liabilities Accounts payable $ 1,291 $ 202 $ 394 $ (1,644 ) $ 243 Other current liabilities 193 291 146 (10 ) 620 Total Current Liabilities 1,484 493 540 (1,654 ) 863 Debt, long-term portion 6,294 291 719 — 7,304 Intercompany note payable 3,042 — 17 (3,059 ) — Other liabilities 153 342 139 — 634 Total Liabilities 10,973 1,126 1,415 (4,713 ) 8,801 Stockholders’ Equity Dynegy Stockholders’ Equity 2,909 12,939 (274 ) (12,665 ) 2,909 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,909 9,897 (274 ) (9,623 ) 2,909 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,909 9,897 (276 ) (9,623 ) 2,907 Total Liabilities and Equity $ 13,882 $ 11,023 $ 1,139 $ (14,336 ) $ 11,708 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 Long-term debt 6,293 122 714 — 7,129 Intercompany note payable 3,042 — 17 (3,059 ) — Other long-term liabilities 147 317 138 — 602 Total Liabilities 10,962 954 1,427 (4,803 ) 8,540 Stockholders’ Equity Dynegy Stockholders’ Equity 2,921 13,284 (267 ) (13,017 ) 2,921 Intercompany note receivable — (3,042 ) — 3,042 — Total Dynegy Stockholders’ Equity 2,921 10,242 (267 ) (9,975 ) 2,921 Noncontrolling interest — — (2 ) — (2 ) Total Equity 2,921 10,242 (269 ) (9,975 ) 2,919 Total Liabilities and Equity $ 13,883 $ 11,196 $ 1,158 $ (14,778 ) $ 11,459
Condensed Consolidating Statements of Operations	Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ 887 $ 236 $ — $ 1,123 Cost of sales, excluding depreciation expense — (412 ) (133 ) — (545 ) Gross margin — 475 103 — 578 Operating and maintenance expense — (159 ) (62 ) — (221 ) Depreciation expense — (146 ) (25 ) — (171 ) General and administrative expense (2 ) (28 ) (7 ) — (37 ) Acquisition and integration costs (3 ) (1 ) — — (4 ) Operating income (loss) (5 ) 141 9 — 145 Earnings from unconsolidated investments — 2 — — 2 Equity in earnings from investments in affiliates 118 — — (118 ) — Interest expense (124 ) (1 ) (17 ) — (142 ) Other income and expense, net 1 — — — 1 Income (loss) before income taxes (10 ) 142 (8 ) (118 ) 6 Income tax expense — (16 ) — — (16 ) Net income (loss) (10 ) 126 (8 ) (118 ) (10 ) Less: Net income attributable to noncontrolling interest — — — — — Net income (loss) attributable to Dynegy Inc. $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Condensed Consolidating Statements of Operations for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Revenues $ — $ — $ 413 $ 219 $ — $ 632 Cost of sales, excluding depreciation expense — — (239 ) (138 ) — (377 ) Gross margin — — 174 81 — 255 Operating and maintenance expense — — (60 ) (51 ) — (111 ) Depreciation expense — — (56 ) (8 ) — (64 ) General and administrative expense (1 ) — (17 ) (12 ) — (30 ) Acquisition and integration costs — — — (90 ) — (90 ) Operating income (loss) (1 ) — 41 (80 ) — (40 ) Equity in losses from investments in affiliates (147 ) — — — 147 — Interest expense (27 ) (93 ) — (16 ) — (136 ) Other income and expense, net (5 ) — — — — (5 ) Income (loss) before income taxes (180 ) (93 ) 41 (96 ) 147 (181 ) Income tax expense — — — — — — Net income (loss) (180 ) (93 ) 41 (96 ) 147 (181 ) Less: Net loss attributable to noncontrolling interest — — — (1 ) — (1 ) Net income (loss) attributable to Dynegy Inc. $ (180 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (180 )
Condensed Consolidating Statements of Comprehensive Income (Loss)	Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (10 ) $ 126 $ (8 ) $ (118 ) $ (10 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — (1 ) Comprehensive income (loss) (11 ) 126 (8 ) (118 ) (11 ) Less: Comprehensive loss attributable to noncontrolling interest — — — — — Total comprehensive income (loss) attributable to Dynegy Inc. $ (11 ) $ 126 $ (8 ) $ (118 ) $ (11 ) Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated Net income (loss) $ (180 ) $ (93 ) $ 41 $ (96 ) $ 147 $ (181 ) Amounts reclassified from accumulated other comprehensive income: Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero (1 ) — — — — (1 ) Other comprehensive loss, net of tax (1 ) — — — — (1 ) Comprehensive income (loss) (181 ) (93 ) 41 (96 ) 147 (182 ) Less: Comprehensive loss attributable to noncontrolling interest — — — (1 ) — (1 ) Total comprehensive income (loss) attributable to Dynegy Inc. $ (181 ) $ (93 ) $ 41 $ (95 ) $ 147 $ (181 )
Condensed Consolidating Statements of Cash Flow	Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2016 (amounts in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ (10 ) $ 175 $ 26 $ — $ 191 CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (4 ) (50 ) (11 ) — (65 ) Net intercompany transfers 339 — — (339 ) — Distributions from unconsolidated affiliates — 8 — — 8 Net cash provided by (used in) investing activities 335 (42 ) (11 ) (339 ) (57 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from borrowing on long term debt — 198 — — 198 Repayments of borrowings (2 ) (3 ) — — (5 ) Dividends paid (5 ) — — — (5 ) Net intercompany transfers — (342 ) 3 339 — Interest rate swap settlement payments (4 ) — — — (4 ) Other financing (2 ) — — — (2 ) Net cash provided by (used in) financing activities (13 ) (147 ) 3 339 182 Net increase (decrease) in cash and cash equivalents 312 (14 ) 18 — 316 Cash and cash equivalents, beginning of period 327 94 84 — 505 Cash and cash equivalents, end of period $ 639 $ 80 $ 102 $ — $ 821 Condensed Consolidating Statements of Cash Flow for the Three Months Ended March 31, 2015 (amounts in millions) Parent Escrow Issuers Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net cash provided by (used in) operating activities $ 2 $ (94 ) $ 46 $ (9 ) $ — $ (55 ) CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures — — (29 ) (11 ) — (40 ) Net intercompany transfers (188 ) — — — 188 — Net cash provided by (used in) investing activities (188 ) — (29 ) (11 ) 188 (40 ) CASH FLOWS FROM FINANCING ACTIVITIES: Repayment of borrowings (2 ) — (23 ) — — (25 ) Dividends paid (7 ) — — — — (7 ) Net intercompany transfers — 94 74 20 (188 ) — Interest rate swap settlement payments (4 ) — — — — (4 ) Other financing (5 ) — — — — (5 ) Net cash provided by (used in) financing activities (18 ) 94 51 20 (188 ) (41 ) Net increase (decrease) in cash and cash equivalents (204 ) — 68 — — (136 ) Cash and cash equivalents, beginning of period 1,642 — 54 174 — 1,870 Cash and cash equivalents, end of period $ 1,438 $ — $ 122 $ 174 $ — $ 1,734

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 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 months ended March 31, 2016 and 2015 is presented below: Segment Data as of and for the Three Months Ended March 31, 2016 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 393 $ 168 $ 562 $ — $ 1,123 Intercompany revenues (13 ) (1 ) 14 — — Total revenues $ 380 $ 167 $ 576 $ — $ 1,123 Depreciation expense $ (39 ) $ (9 ) $ (122 ) $ (1 ) $ (171 ) General and administrative expense — — — (37 ) (37 ) Acquisition and integration costs — — — (4 ) (4 ) Operating income (loss) $ 54 $ 14 $ 120 $ (43 ) $ 145 Earnings from unconsolidated investments — — 2 — 2 Interest expense (1 ) (17 ) (1 ) (123 ) (142 ) Other income and expense, net — — — 1 1 Income before income taxes 6 Income tax expense — — — (16 ) (16 ) Net loss (10 ) Less: Net loss attributable to noncontrolling interest — Net loss attributable to Dynegy Inc. $ (10 ) Total assets—domestic $ 2,269 $ 898 $ 7,815 $ 726 $ 11,708 Investment in unconsolidated affiliate $ — $ — $ 185 $ — $ 185 Capital expenditures $ (19 ) $ (11 ) $ (31 ) $ (4 ) $ (65 ) Segment Data as of and for the Three Months Ended March 31, 2015 (amounts in millions) Coal IPH Gas Other and Eliminations Total Domestic: Unaffiliated revenues $ 154 $ 219 $ 259 $ — $ 632 Intercompany revenues (12 ) — 12 — — Total revenues $ 142 $ 219 $ 271 $ — $ 632 Depreciation expense $ (10 ) $ (8 ) $ (45 ) $ (1 ) $ (64 ) General and administrative expense — — — (30 ) (30 ) Operating income (loss) $ 7 $ 22 $ 52 $ (121 ) $ (40 ) Interest expense — — — (136 ) (136 ) Other income and expense, net — — — (5 ) (5 ) Loss before income taxes (181 ) Income tax expense — — — — — Net loss (181 ) Less: Net loss attributable to noncontrolling interest (1 ) Net loss attributable to Dynegy Inc. $ (180 ) Total assets—domestic $ 1,162 $ 1,037 $ 2,105 $ 6,827 $ 11,131 Capital expenditures $ (3 ) $ (11 ) $ (24 ) $ (2 ) $ (40 )

Basis of Presentation and Org42

Basis of Presentation and Organization (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)segment	Dec. 31, 2015USD ($)
Debt Instrument [Line Items]
Number of reportable segments | segment	3
Carrying amount	$ 7,632	$ 7,416
Genco
Debt Instrument [Line Items]
Carrying amount	$ 825

Acquisitions (Delta Stock Purch

Acquisitions (Delta Stock Purchase Agreement) (Details) $ / shares in Units, $ in Millions	Feb. 24, 2016USD ($)Position$ / sharesMWshares	Mar. 31, 2016USD ($)$ / shares	Dec. 31, 2015$ / shares	Mar. 31, 2015USD ($)
Business Acquisition [Line Items]
Common stock, par value (in dollars per share) | $ / shares		$ 0.01	$ 0.01
Bridge Loan
Business Acquisition [Line Items]
Short-term debt				$ 0
Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Number of power facilities acquired | MW	8,700
Cash	$ 3,300
Purchase agreement termination rights, closinig period	12 months
Acquisition costs		$ 2
Delta Stock Purchase Agreement | Dynegy, Inc.
Business Acquisition [Line Items]
Ownership interest, percentage	65.00%
Delta Stock Purchase Agreement | Energy Capital Partners
Business Acquisition [Line Items]
Ownership interest, percentage	35.00%
Delta Stock Purchase Agreement | Committed Debt Facilities
Business Acquisition [Line Items]
Short-term debt	$ 2,250
Delta Stock Purchase Agreement | Committed Debt Facilities | Bridge Loan | Energy Capital Partners
Business Acquisition [Line Items]
Short-term debt	400
Delta Stock Purchase Agreement | Committed Debt Facilities | Senior secured debt
Business Acquisition [Line Items]
Short-term debt	1,850
Delta Stock Purchase Agreement | Equity Commitments
Business Acquisition [Line Items]
Other Commitment	1,185
Delta Stock Purchase Agreement | Equity Commitments | Dynegy, Inc.
Business Acquisition [Line Items]
Other Commitment	770
Delta Stock Purchase Agreement | Equity Commitments | Energy Capital Partners
Business Acquisition [Line Items]
Other Commitment	$ 415
Delta Stock Purchase Agreement | Atlas Power Finance, LLC
Business Acquisition [Line Items]
Percent of voting interests acquired (as a percentage)	100.00%
PIPE Stock Purchase Agreement | Dynegy, Inc.
Business Acquisition [Line Items]
Stock issued during the period, shares, acquisitions | shares	13,711,152
Common stock, par value (in dollars per share) | $ / shares	$ 0.01
Stock issued during the period, value	$ 150
Number of Board of Directors positions | Position	1
Investor Rights Agreement, Minimum stock ownership percentage	10.00%
Guarantee Obligations | Delta Stock Purchase Agreement
Business Acquisition [Line Items]
Number of claims and amount of accrued indemnifications, if any	$ 132

Acquisitions (ECP Purchase Agre

Acquisitions (ECP Purchase Agreements) (Details) $ in Millions	Apr. 01, 2015USD ($)FacilitiesMW
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
Number 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) - Duke Midwest Purchase Agreement $ in Billions	Apr. 02, 2015USD ($)AffiliateFacilitiesMW
Business Acquisition [Line Items]
Retail Energy Business acquired	1
Percent of voting interests acquired (as a percentage)	100.00%
Number of affiliates | Affiliate	2
Combined cycle gas facilities acquired	3
Natural gas power facilities acquired	2
Number of power facilities acquired | MW	6,200
Cash | $	$ 2.8
Gas
Business Acquisition [Line Items]
Natural gas power facilities acquired	5
Coal
Business Acquisition [Line Items]
Oil-Fired power facilities	1
Coal-Fired power facilities	5
Parent | Coal
Business Acquisition [Line Items]
Coal-Fired power facilities	2
Third Parties | Coal
Business Acquisition [Line Items]
Coal-Fired power facilities	3

Acquisitions (Business Combinat

Acquisitions (Business Combination Accounting) (Details) - USD ($) $ in Millions	Apr. 01, 2015	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2025	Dec. 31, 2015	Dec. 31, 2019
Business Acquisition [Line Items]
Goodwill		$ 797			$ 797
Bridge Loan
Business Acquisition [Line Items]
Bridge loan facility			$ 0
EquiPower and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Period of evaluation	1 year
Equity interests issued and issuable					105
Goodwill					$ 797
Acquisition and integration costs		0	90
Revenues and gains recognized		661
Net gains and losses		$ 157
EquiPower and Duke Midwest Acquisitions | Bridge Loan
Business Acquisition [Line Items]
Commitment fees related to bridge facility			48
EquiPower and Duke Midwest Acquisitions | Acquisition Advisory and Consulting Fees
Business Acquisition [Line Items]
Acquisition and integration costs			$ 42
EquiPower and Duke Midwest Acquisitions | 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%
EquiPower and Duke Midwest Acquisitions | Minimum | Gas
Business Acquisition [Line Items]
Discount rate (as a percentage)		8.00%
EquiPower and Duke Midwest Acquisitions | Minimum | Coal
Business Acquisition [Line Items]
Discount rate (as a percentage)		9.00%
EquiPower and Duke Midwest Acquisitions | Maximum | Gas
Business Acquisition [Line Items]
Discount rate (as a percentage)		10.00%
EquiPower and Duke Midwest Acquisitions | Maximum | Coal
Business Acquisition [Line Items]
Discount rate (as a percentage)		13.00%
EquiPower Acquisition
Business Acquisition [Line Items]
Number of shares issued	3,460,053
Equity interests issued and issuable	$ 105
Goodwill	$ 797

Acquisitions (Schedule of Asset

Acquisitions (Schedule of Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Millions	Apr. 02, 2015	Apr. 01, 2015	Dec. 31, 2015	Mar. 31, 2016
Business Acquisition [Line Items]
Goodwill			$ 797	$ 797
EquiPower and Duke Midwest Acquisitions
Business Acquisition [Line Items]
Cash			6,150
Equity instruments (3,460,053 common shares of Dynegy)			105
Net working capital adjustment			197
Fair value of total consideration transferred			6,452
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			32
Debt, current portion			39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)			164
Asset retirement obligations			92
Intangible liabilities (including current portion of $24 million and $58 million, respectively)			166
Deferred income taxes, net			506
Other long-term liabilities			40
Total liabilities assumed			1,162
Identifiable net assets acquired			5,655
Goodwill			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		22
Debt, current portion		39
Liabilities from risk management activities (including current portion of $41 million and zero, respectively)		57
Asset retirement obligations		43
Intangible liabilities (including current portion of $24 million and $58 million, respectively)		73
Deferred income taxes, net		506
Other long-term liabilities		0
Total liabilities assumed		767
Identifiable net assets acquired		2,864
Goodwill		797
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 Ass48

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	3 Months Ended
	Mar. 31, 2015USD ($)
Business Acquisition [Line Items]
Revenues	$ 1,622
Net income	80
Noncontrolling Interest
Business Acquisition [Line Items]
Net income	(1)
Parent
Business Acquisition [Line Items]
Net income	$ 81

Unconsolidated Investments (Det

Unconsolidated Investments (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Apr. 01, 2015MW
Schedule of Equity Method Investments [Line Items]
Investment in unconsolidated affiliate	$ 185		$ 190
Income from unconsolidated investments	2	$ 0
Accounts receivable, net	339		402
Elwood
Schedule of Equity Method Investments [Line Items]
Percent of voting interests acquired (as a percentage)				50.00%
Number of power facilities acquired | MW				1,576
Investment in unconsolidated affiliate	185		190
Identifiable net assets acquired	89
Distributions from unconsolidated investments	8
Accounts receivable, net	$ 2		$ 3

Risk Management Activities, D51

Risk Management Activities, Derivatives and Financial Instruments (Narratives) (Details) $ in Millions	3 Months Ended
	Mar. 31, 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	$ 35
Fair value of collateral	$ 21

Risk Management Activities, D52

Risk Management Activities, Derivatives and Financial Instruments (Schedule of Derivative Contracts and Interest Rate Swaps) (Details) $ in Millions		Mar. 31, 2016USD ($)dollarswarrantgaltBTUMWhshares	Dec. 31, 2015USD ($)
Derivative [Line Items]
Number of securities called by each warrant or right | shares		1
Commodity contracts: | Prepayments and Other Current Assets
Derivative [Line Items]
Margin and collateral netting		$ 79	$ 106
Not Designated as Hedging Instrument
Derivative [Line Items]
Derivative Fair Value, Asset		653	403
Margin and collateral netting		$ 79	$ 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]	$ (6)
Not Designated as Hedging Instrument | Future contracts | Electricity derivatives | Short
Derivative [Line Items]
Number of instruments held | MWh	[3]	(50,000,000)
Derivative Fair Value, Asset	[2],[3]	$ 148
Not Designated as Hedging Instrument | Future contracts | Electricity basis derivatives | Short
Derivative [Line Items]
Number of instruments held | MWh	[4]	(7,000,000)
Derivative Fair Value, Asset	[2],[4]	$ 3
Not Designated as Hedging Instrument | Future contracts | Natural gas derivatives | Long
Derivative [Line Items]
Number of instruments held | BTU	[3]	(362,000,000)
Derivative Fair Value, Liability	[2],[3]	$ (168)
Not Designated as Hedging Instrument | Future contracts | Natural gas basis derivatives | Long
Derivative [Line Items]
Number of instruments held | BTU		(83,000,000)
Derivative Fair Value, Liability	[2]	$ (3)
Not Designated as Hedging Instrument | Future contracts | Diesel fuel | Long
Derivative [Line Items]
Number of instruments held | gal		(2,000,000)
Derivative Fair Value, Liability	[2]	$ (3)
Not Designated as Hedging Instrument | Future contracts | Coal derivatives
Derivative [Line Items]
Number of instruments held | t	[5]	(1,000,000)
Not Designated as Hedging Instrument | Future contracts | Coal derivatives | Long
Derivative [Line Items]
Derivative Fair Value, Liability	[2],[5]	$ (15)
Not Designated as Hedging Instrument | Future contracts | Emissions derivatives | Long
Derivative [Line Items]
Number of instruments held | t		(4,000,000)
Derivative Fair Value, Liability	[2]	$ (3)
Not Designated as Hedging Instrument | Interest rate swaps | Long
Derivative [Line Items]
Number of instruments held | dollars		(775,000,000)
Derivative Fair Value, Liability	[2]	$ (46)
[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 $79 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, D53

Risk Management Activities, Derivatives and Financial Instruments (Schedule of Derivative Instruments in the Balance Sheet) (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Risk Management Activities, Derivatives and Financial Instruments
Derivative Asset, Gross Fair Value	$ 653	$ 403
Derivative Asset, Contract Netting	(424)	(285)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	229	118
Derivative Liabilities, Gross Fair Value	(746)	(606)
Derivative Liability, Contract Netting	(424)	(285)
Margin and collateral netting	79	106
Derivative Liabilities, Net Fair Value	(243)	(215)
Derivative Assets (Liabilities), Gross Fair Value	(93)	(203)
Derivative Asset and Liability Contract Netting	0	0
Derivative Asset And Liability, Collateral, Obligation to Return Cash, Offset	79	106
Derivative Assets (Liabilities), Net Fair Value	(14)	(97)
Commodity Contract | Assets from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Asset, Gross Fair Value	653	403
Derivative Asset, Contract Netting	(424)	(285)
Derivative Asset, Collateral, Obligation to Return Cash, Offset	0	0
Derivative Assets, Net Fair Value	229	118
Commodity Contract | Liabilities from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(694)	(557)
Derivative Liability, Contract Netting	(424)	(285)
Margin and collateral netting	79	106
Derivative Liabilities, Net Fair Value	(191)	(166)
Interest rate contracts | Liabilities from Risk Management Activities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(46)	(42)
Derivative Liability, Contract Netting	0	0
Margin and collateral netting	0	0
Derivative Liabilities, Net Fair Value	(46)	(42)
Common stock warrants | Other Liabilities
Risk Management Activities, Derivatives and Financial Instruments
Derivative Liabilities, Gross Fair Value	(6)	(7)
Derivative Liability, Contract Netting	0	0
Margin and collateral netting	0	0
Derivative Liabilities, Net Fair Value	$ (6)	$ (7)

Risk Management Activities, D54

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	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Gross collateral posted with counterparties	$ 140	$ 162
Less: Collateral netted against risk management liabilities	79	106
Net collateral within Prepayments and other current assets	$ 61	$ 56

Risk Management Activities, D55

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
	Mar. 31, 2016	Mar. 31, 2015
Commodity Contract | Revenues
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	$ 192	$ 19
Interest rate contracts | Interest expense
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	(8)	(9)
Common stock warrants | Other income and (expense), net
Derivative Instruments, Gain (Loss) [Line Items]
Recognized gain (loss) on derivatives	$ 1	$ (5)

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	Mar. 31, 2016	Dec. 31, 2015
Assets:
Total assets from commodity risk management activities	$ 653	$ 403
Liabilities:
Liabilities from commodity risk management activities:	(694)	(557)
Liabilities from interest rate contracts	(46)	(42)
Total liabilities	(746)	(606)
Electricity Derivatives
Assets:
Assets from commodity risk management activities:	562	348
Liabilities:
Liabilities from commodity risk management activities:	(411)	(325)
Natural gas derivatives
Assets:
Assets from commodity risk management activities:	81	42
Liabilities:
Liabilities from commodity risk management activities:	(252)	(192)
Emissions derivatives
Assets:
Assets from commodity risk management activities:	1
Liabilities:
Liabilities from commodity risk management activities:	(4)
Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	(3)	(4)
Coal derivatives
Assets:
Assets from commodity risk management activities:	9	13
Liabilities:
Liabilities from commodity risk management activities:	(24)	(36)
Liabilities from outstanding common stock warrants
Liabilities:
Liabilities from outstanding common stock warrants	(6)	(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	(6)	(7)
Level 1 | Electricity Derivatives
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	0	0
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 1 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0
Level 1 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	0	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	(6)	(7)
Level 2
Assets:
Total assets from commodity risk management activities	590	358
Liabilities:
Liabilities from commodity risk management activities:	(597)	(464)
Liabilities from interest rate contracts	(46)	(42)
Total liabilities	(643)	(506)
Level 2 | Electricity Derivatives
Assets:
Assets from commodity risk management activities:	515	308
Liabilities:
Liabilities from commodity risk management activities:	(347)	(267)
Level 2 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	67	40
Liabilities:
Liabilities from commodity risk management activities:	(220)	(158)
Level 2 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	1
Liabilities:
Liabilities from commodity risk management activities:	(4)
Level 2 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	(3)	(4)
Level 2 | Coal derivatives
Assets:
Assets from commodity risk management activities:	7	10
Liabilities:
Liabilities from commodity risk management activities:	(23)	(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	63	45
Liabilities:
Liabilities from commodity risk management activities:	(97)	(93)
Liabilities from interest rate contracts	0	0
Total liabilities	(97)	(93)
Level 3 | Electricity Derivatives
Assets:
Assets from commodity risk management activities:	47	40
Liabilities:
Liabilities from commodity risk management activities:	(64)	(58)
Level 3 | Natural gas derivatives
Assets:
Assets from commodity risk management activities:	14	2
Liabilities:
Liabilities from commodity risk management activities:	(32)	(34)
Level 3 | Emissions derivatives
Assets:
Assets from commodity risk management activities:	0
Liabilities:
Liabilities from commodity risk management activities:	0
Level 3 | Diesel fuel derivatives
Liabilities:
Liabilities from commodity risk management activities:	0	0
Level 3 | Coal derivatives
Assets:
Assets from commodity risk management activities:	2	3
Liabilities:
Liabilities from commodity risk management activities:	(1)	(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 MWh in Millions, BTU in Millions	3 Months Ended
	Mar. 31, 2016USD ($)BTUMWh
Forward contracts - power
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | MWh	(4)	[1]
Fair value of derivatives held	$ (12,000,000)	[1]
Forward contracts - power | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread	5	[1]
Forward contracts - power | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Basis spread	$ 7	[1]
FTRs
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | MWh	15
Fair value of derivatives held	$ (5,000,000)
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	$ 9
Natural gas derivatives
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | BTU	75
Fair value of derivatives held	$ (18,000,000)
Natural gas derivatives | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Bid-ask spread	1.20
Natural gas derivatives | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Bid-ask spread	$ 1.50
Forward contracts - coal
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Number of instruments held | MWh	0	[1]
Fair value of derivatives held	$ 1,000,000	[1]
Forward contracts - coal | Minimum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Bid-ask spread	4.20
Forward contracts - coal | Maximum
Fair Value Inputs, Equity, Quantitative Information [Line Items]
Bid-ask spread	$ 5.10
[1]	Represents forward financial and physical transactions at illiquid pricing locations.

Fair Value Measurements (Sche58

Fair Value Measurements (Schedule of Changes in Fair Value of Financial Instruments) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Unrealized gains (losses) relating to instruments held as of September 30, 2015		$ 109	$ 27
Level 3
Fair Value Measurements
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(34)	4	$ (48)	$ (4)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		(13)	(3)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements	[1]	1	5
Unrealized gains (losses) relating to instruments held as of September 30, 2015		13	3
Level 3 | Electricity Derivatives
Fair Value Measurements
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(17)	4	(18)	(4)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		(8)	(3)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements	[1]	(7)	5
Unrealized gains (losses) relating to instruments held as of September 30, 2015		8	3
Level 3 | Natural gas derivatives
Fair Value Measurements
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		(18)	0	(32)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		(5)	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements	[1]	9	0
Unrealized gains (losses) relating to instruments held as of September 30, 2015		5	0
Level 3 | Coal derivatives
Fair Value Measurements
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis with Unobservable Inputs		1	0	$ 2	$ 0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		0	0
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements	[1]	(1)	0
Unrealized gains (losses) relating to instruments held as of September 30, 2015		$ 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 (Sche59

Fair Value Measurements (Schedule of Financial Assets and Liabilities) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Fair value of Financial Instruments
Unamortized discount and debt issuance costs	[1]	$ 220	$ 207
Not Designated as Hedging Instrument
Fair value of Financial Instruments
Margin and collateral netting		79	106
Commodity Contract | Prepayments and Other Current Assets
Fair value of Financial Instruments
Margin and collateral netting		$ 79	106
5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Stated interest rate		5.875%
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%
Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Stated interest rate		7.625%
Dynegy, Inc.
Fair value of Financial Instruments
Debt issuance cost		$ 66	68
Dynegy, Inc. | Term Facilities Tranche B-2 | Secured Debt
Fair value of Financial Instruments
Unamortized discount and debt issuance costs		$ 13	14
Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Stated interest rate		5.875%
Dynegy, Inc. | Equipment financing agreements
Fair value of Financial Instruments
Unamortized discount		$ 14	14
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. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Stated interest rate		7.625%
Dynegy, Inc. | Forward capacity agreement
Fair value of Financial Instruments
Unamortized discount		$ 21
Genco | Unsecured Debt
Fair value of Financial Instruments
Unamortized loan commitment and origination fees and unamortized discounts or premiums		$ 106	111
Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Stated interest rate		7.95%
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%
Carrying Amount | Dynegy, Inc. | Common stock warrants
Fair value of Financial Instruments
Common stock warrants	[2]	$ (6)	(7)
Carrying Amount | Dynegy, Inc. | Interest rate contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest rate derivatives	[3]	(46)	(42)
Carrying Amount | Dynegy, Inc. | Commodity Contract | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[4]	(41)	(154)
Carrying Amount | Dynegy, Inc. | Term Facilities Tranche B-2
Fair value of Financial Instruments
Long-term debt, gross	[3],[5]	(765)	(766)
Carrying Amount | Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(492)	(491)
Carrying Amount | Dynegy, Inc. | Inventory financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[7]	(134)	(136)
Carrying Amount | Dynegy, Inc. | Equipment financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[7],[8]	(62)	(61)
Carrying Amount | Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(2,078)	(2,077)
Carrying Amount | Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(1,729)	(1,729)
Carrying Amount | Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(1,235)	(1,235)
Carrying Amount | Dynegy, Inc. | Forward capacity agreement
Fair value of Financial Instruments
Long-term debt, gross	[7],[9]	(198)	0
Carrying Amount | Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	(225)	(225)
Carrying Amount | Genco | Senior Notes Series H 7.00% Due 2018
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	(279)	(276)
Carrying Amount | Genco | Senior Notes Series I 6.30% Due 2020
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	(215)	(213)
Fair Value | Dynegy, Inc. | Common stock warrants
Fair value of Financial Instruments
Common stock warrants	[2]	(6)	(7)
Fair Value | Dynegy, Inc. | Interest rate contracts | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Interest rate derivatives	[3]	(46)	(42)
Fair Value | Dynegy, Inc. | Commodity Contract | Not Designated as Hedging Instrument
Fair value of Financial Instruments
Commodity-based derivative contracts	[4]	(41)	(154)
Fair Value | Dynegy, Inc. | Term Facilities Tranche B-2
Fair value of Financial Instruments
Long-term debt, gross	[3],[5]	(766)	(754)
Fair Value | Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(423)	(404)
Fair Value | Dynegy, Inc. | Inventory financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[7]	(134)	(136)
Fair Value | Dynegy, Inc. | Equipment financing agreements
Fair value of Financial Instruments
Long-term debt, gross	[7],[8]	(62)	(61)
Fair Value | Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(2,090)	(1,985)
Fair Value | Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(1,628)	(1,531)
Fair Value | Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Fair value of Financial Instruments
Long-term debt, gross	[3],[6]	(1,131)	(1,078)
Fair Value | Dynegy, Inc. | Forward capacity agreement
Fair value of Financial Instruments
Long-term debt, gross	[7],[9]	(198)	0
Fair Value | Genco | Senior Notes Series F 7.95% Due 2032
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	(88)	(162)
Fair Value | Genco | Senior Notes Series H 7.00% Due 2018
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	(120)	(204)
Fair Value | Genco | Senior Notes Series I 6.30% Due 2020
Fair value of Financial Instruments
Long-term debt, gross	[3],[10]	$ (85)	$ (148)
[1]	Includes $80 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion.
[2]	The fair value of the common stock warrants is classified as Level 1 within the fair value hierarchy levels.
[3]	The fair values of these financial instruments are classified as Level 2 within the fair value hierarchy levels.
[4]	Carrying amount of commodity-based derivative contracts excludes $79 million and $106 million of cash posted as collateral, as of March 31, 2016 and December 31, 2015, respectively.
[5]	Carrying amount includes an unamortized discount and debt issuance costs of $13 million and $14 million as of March 31, 2016 and December 31, 2015, respectively. Please read Note 12—Debt for further discussion.
[6]	Combined carrying amounts include debt issuance costs of $66 million and $68 million as of March 31, 2016 and December 31, 2015, respectively.
[7]	The fair values of these financial instruments are classified as Level 3 within the fair value hierarchy levels and are based on internal estimates.
[8]	Carrying amounts for the equipment financing agreement include unamortized discounts of $14 million and $14 million as of March 31, 2016 and December 31, 2015, respectively.
[9]	Carrying amount includes an unamortized discount of $21 million as of March 31, 2016.
[10]	Combined carrying amounts include unamortized discounts and debt issuance costs of $106 million and $111 million as of March 31, 2016 and December 31, 2015, respectively. Please read Note 12—Debt for further discussion.

Accumulated Other Comprehensi60

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income [Roll Forward]
Beginning of period		$ 19	$ 20
Amortization of unrecognized prior service credit and actuarial gain (net of tax of zero and zero, respectively)	[1]	(1)	(1)
Net current period other comprehensive loss, net of tax		(1)	(1)
End of period		18	19
Tax on amortization of unrecognized prior service cost (credit) and actuarial loss (gain)	[1]	$ (1)	$ (1)
[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 15—Pension and Other Post-Employment Benefit Plans for further discussion.

Inventory (Summary of Inventori

Inventory (Summary of Inventories) (Details) - USD ($) $ in Millions		Mar. 31, 2016		Dec. 31, 2015
Inventory Disclosure [Abstract]
Materials and supplies		$ 176		$ 175
Coal		344	[1]	350
Fuel oil		17	[1]	17
Emissions allowances	[2]	39		51
Other		3		4
Total		$ 579		$ 597
[1]	At March 31, 2016, approximately $46 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 12—Debt—Brayton Point Inventory Financing for further discussion.
[2]	At March 31, 2016 and December 31, 2015, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 12—Debt—Emissions Repurchase Agreements for further discussion.

Inventory (Inventory Summary Fo

Inventory (Inventory Summary Footnote) (Details) - USD ($) $ in Millions	Mar. 31, 2016	[1]	Dec. 31, 2015
Inventory [Line Items]
Coal	$ 344		$ 350
Fuel oil	17		17
Inventory financing agreements
Inventory [Line Items]
Coal	46		44
Fuel oil	$ 12		$ 16
[1]	At March 31, 2016, approximately $46 million and $12 million of the coal and fuel oil inventory, respectively, are part of an inventory financing agreement. At December 31, 2015, approximately $44 million and $16 million of the coal and fuel oil inventory, respectively, were part of an inventory financing agreement. Please read Note 12—Debt—Brayton Point Inventory Financing for further discussion.

Property, Plant and Equipment63

Property, Plant and Equipment (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	$ 9,301	$ 9,235
Accumulated depreciation	(1,059)	(888)
Property, plant and equipment, net	8,242	8,347
Power generation
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	8,240	8,178
Building and Building Improvements [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	958	956
Office and miscellaneous Equipment [Member]
Property, Plant and Equipment, Net, by Type [Abstract]
Property, plant and equipment	$ 103	$ 101

Joint Ownership of Generating64

Joint Ownership of Generating Facilities (Details) - USD ($) $ in Millions		Mar. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Property, plant and equipment		$ 9,301	$ 9,235
Accumulated depreciation		(1,059)	(888)
Property, plant and equipment, net		$ 8,242	$ 8,347
Miami Fort
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	64.00%	64.00%
Property, plant and equipment	[1]	$ 205	$ 207
Accumulated depreciation	[1]	(22)	(16)
Construction Work in Progress	[1]	3	3
Property, plant and equipment, net	[1]	$ 186	$ 194
J.M. Stuart
Schedule of Equity Method Investments [Line Items]
Ownership Interest		39.00%	39.00%
Property, plant and equipment		$ 32	$ 32
Accumulated depreciation		(5)	(4)
Construction Work in Progress		23	20
Property, plant and equipment, net		$ 50	$ 48
Conesville
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	40.00%	40.00%
Property, plant and equipment	[1]	$ 60	$ 61
Accumulated depreciation	[1]	(1)	(2)
Construction Work in Progress	[1]	4	4
Property, plant and equipment, net	[1]	$ 63	$ 63
W.M. Zimmer
Schedule of Equity Method Investments [Line Items]
Ownership Interest		46.50%	46.50%
Property, plant and equipment		$ 99	$ 99
Accumulated depreciation		(11)	(10)
Construction Work in Progress		10	11
Property, plant and equipment, net		$ 98	$ 100
Killen Station
Schedule of Equity Method Investments [Line Items]
Ownership Interest	[1]	33.00%	33.00%
Property, plant and equipment	[1]	$ 17	$ 17
Accumulated depreciation	[1]	(1)	(1)
Construction Work in Progress	[1]	2	2
Property, plant and equipment, net	[1]	$ 18	$ 18
[1]	Facilities not operated by Dynegy.

Intangible Assets and Liabili65

Intangible Assets and Liabilities (Intangible Assets and Liabilities) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	$ 306	$ 306
Accumulated Amortization	(181)	(142)
Net Carrying Amount	125	164
Electricity Contract Liability, Gross	(30)	(30)
Electricity Contract Liability, Accumulated Amortization	25	19
Electricity Contract Liability, Net	(5)	(11)
Coal Contract Liability, Gross	(116)	(134)
Coal Contract Liability, Accumulated Amortization	76	82
Coal Contract Liability, Net	(40)	(52)
Coal Transport Contract Liability, Gross	(104)	(104)
Coal Transport Liability, Accumulated Amortization	71	64
Coal Transport Liability, Net	(33)	(40)
Gas Transport Contract Liability, Gross	(41)	(64)
Gas Transport Liability, Accumulated Amortization	4	27
Gas Transport Liability, Net	(37)	(37)
Intangible Liabilities, Gross	(291)	(332)
Intangible Liabilities, Accumulated Amortization	176	192
Intangible Liabilities, Net	(115)	(140)
Intangible Assets (Liabilities), Gross	15	(26)
Intangible Assets (Liabilities), Accumulated Amortization	(5)	50
Intangible Assets (Liabilities), Net	10	24
Electricity Derivatives
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	260	260
Accumulated Amortization	(148)	(126)
Net Carrying Amount	112	134
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Gross Carrying Amount	46	46
Accumulated Amortization	(33)	(16)
Net Carrying Amount	$ 13	$ 30

Intangible Assets and Liabili66

Intangible Assets and Liabilities (Amortization of Intangible Assets and Liabilities) (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles		$ 14	$ (4)
Electricity contracts, net
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[1]	16	7
Coal contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	(12)	(3)
Coal transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	(7)	(6)
Gas transport contracts
Intangible Assets and Liabilities [Line Items]
Amortization of intangibles	[2]	$ 17	$ (2)
[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.

Debt (Schedule of Long-term Deb

Debt (Schedule of Long-term Debt) (Details) - USD ($) $ in Millions		Mar. 31, 2016	Mar. 18, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Carrying amount		$ 7,632		$ 7,416
Unamortized debt discounts and issuance costs (1)	[1]	220		207
Total Debt		7,412		7,209
Less: Current maturities, including unamortized debt discounts and issuance costs, net		108		80
Debt, long-term portion		$ 7,304		7,129
5.875% Senior Notes, Due June 2023
Debt Instrument [Line Items]
Stated interest rate		5.875%
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%
Senior Notes 7.625%, Due 2024
Debt Instrument [Line Items]
Stated interest rate		7.625%
Dynegy, Inc. | Tranche B-2 Term Loan, Due 2020
Debt Instrument [Line Items]
Carrying amount		$ 778		780
Dynegy, Inc. | 5.875% Senior Notes, Due June 2023
Debt Instrument [Line Items]
Carrying amount		$ 500		500
Stated interest rate		5.875%
Dynegy, Inc. | Forward capacity agreement
Debt Instrument [Line Items]
Carrying amount		$ 219		0
Dynegy, Inc. | Inventory financing agreements
Debt Instrument [Line Items]
Carrying amount		134		136
Dynegy, Inc. | Equipment financing agreements
Debt Instrument [Line Items]
Carrying amount		76		75
Dynegy, Inc. | Senior Notes 6.75%, Due 2019
Debt Instrument [Line Items]
Carrying amount		$ 2,100		2,100
Stated interest rate		6.75%
Dynegy, Inc. | Senior Notes 7.375%, Due 2022
Debt Instrument [Line Items]
Carrying amount		$ 1,750		1,750
Stated interest rate		7.375%
Dynegy, Inc. | Senior Notes 7.625%, Due 2024
Debt Instrument [Line Items]
Carrying amount		$ 1,250		1,250
Stated interest rate		7.625%
Genco
Debt Instrument [Line Items]
Carrying amount		$ 825
Genco | Senior Notes Series H 7.00% Due 2018
Debt Instrument [Line Items]
Carrying amount		$ 300		300
Stated interest rate		7.00%
Genco | Senior Notes Series I 6.30% Due 2020
Debt Instrument [Line Items]
Carrying amount		$ 250		250
Stated interest rate		6.30%
Genco | Senior Notes Series F 7.95% Due 2032
Debt Instrument [Line Items]
Carrying amount		$ 275		275
Stated interest rate		7.95%
Accounting Standards Update 2015-03
Debt Instrument [Line Items]
Unamortized debt discounts and issuance costs (1)				$ 80
[1]	Includes $80 million related to the reclassification of unamortized debt issuance costs as of December 31, 2015. Please read Note 2—Accounting Policies for further discussion.

Debt (Narratives) (Details)

Debt (Narratives) (Details)

Mar. 18, 2016USD ($)

Mar. 27, 2015USD ($)

Apr. 23, 2013

Mar. 31, 2016USD ($)tranche

Dec. 31, 2015USD ($)

Aug. 20, 2015USD ($)

Aug. 14, 2015USD ($)

Apr. 02, 2015USD ($)

Apr. 01, 2015USD ($)

Sep. 18, 2014USD ($)

Jan. 29, 2014USD ($)

Dec. 02, 2013USD ($)

Debt Instrument [Line Items]

Carrying amount

$ 7,632,000,000

$ 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%

5.875% Senior Notes, Due June 2023

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 500,000,000

Stated interest rate

5.875%

Genco Senior Notes Series F, H, and I

Debt Instrument [Line Items]

Amount of unsecured senior notes

$ 825,000,000

Revolving Credit Facility

Debt Instrument [Line Items]

Number of tranches | tranche

3

Letter of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 55,000,000

Letters of credit outstanding

$ (55,000,000)

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) [Member]

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 2,225,000,000

Illinois Power Marketing

Debt Instrument [Line Items]

Letters of credit outstanding

(22,000,000)

Illinois Power Marketing | Letter of Credit and Reimbursement Agreement

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 25,000,000

Savings deposits

14,000,000

Letters of credit outstanding

$ (13,000,000)

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

Debt Instrument [Line Items]

Stated interest rate

5.875%

Carrying amount

$ 500,000,000

500,000,000

Dynegy, Inc. | Inventory financing agreements

Debt Instrument [Line Items]

Carrying amount

134,000,000

136,000,000

Dynegy, Inc. | Equipment financing agreements

Debt Instrument [Line Items]

Unamortized discount

14,000,000

14,000,000

Carrying amount

76,000,000

75,000,000

Dynegy, Inc. | Forward capacity agreement

Debt Instrument [Line Items]

Unamortized discount

21,000,000

Carrying amount

$ 219,000,000

0

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

Debt Instrument [Line Items]

Stated interest rate

6.75%

Carrying amount

$ 2,100,000,000

2,100,000,000

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

Debt Instrument [Line Items]

Stated interest rate

7.375%

Carrying amount

$ 1,750,000,000

1,750,000,000

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

Debt Instrument [Line Items]

Stated interest rate

7.625%

Carrying amount

$ 1,250,000,000

$ 1,250,000,000

RGGI Repurchase Agreement

Debt Instrument [Line Items]

Assets sold under agreements to repurchase, carrying amount

$ 78,000,000

$ 20,000,000

$ 58,000,000

Assets sold under agreements to repurchase, carry rate

3.31%

3.56%

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 Credit Facility | Line of Credit

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 1,425,000,000

Line of credit facility, amount outstanding

0

Revolving Credit Facility | Letter of Credit

Debt Instrument [Line Items]

Letters of credit outstanding

(441,000,000)

Revolving Credit Facility | Illinois Power Marketing

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 25,000,000

Credit facility tenor

2 years

Credit facility optional extension period

1 year

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

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 600,000,000

EquiPower Acquisition | Inventory financing agreements

Debt Instrument [Line Items]

Maximum borrowing capacity

$ 15,000,000

Letters of credit outstanding

(56,000,000)

Debt Instrument, Collateral Amount

$ 12,000,000

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

Debt Instrument [Line Items]

Maximum borrowing capacity

475,000,000

EquiPower Acquisition | Revolving Credit 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)

0.75%

LIBOR | Illinois Power Marketing

Debt Instrument [Line Items]

Basis spread on variable rate (as a percentage)

0.50%

Coal | 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

[3],[4]

$ (62,000,000)

Interest rate swaps | Term Facilities Tranche B-2

Debt Instrument [Line Items]

Derivative, notional amount

$ 775,000,000

Derivative, average fixed interest rate (as a percentage)

3.19%

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

1.00%

[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]

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

[4]

The fair values of these financial instruments are classified as Level 3 within the fair value hierarchy levels and are based on internal estimates.

Commitments and Contingencies (

Commitments and Contingencies (Legal Proceedings) (Details) $ in Millions	Dec. 16, 2014USD ($)	Sep. 30, 2010USD ($)	Jun. 30, 2007USD ($)	Mar. 31, 2016state
Gas Index Pricing Litigation | Pending Litigation
Loss Contingencies [Line Items]
Number of States with pending litigation | state				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

Commitments and Contingencies70

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	Mar. 31, 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 Contingencies71

Commitments and Contingencies (Indemnifications and Guarantees) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Feb. 24, 2016
LS Power Indemnities
Loss Contingencies [Line Items]
Number of claims and amount of accrued indemnifications, if any	$ 0
Delta Stock Purchase Agreement | Parent
Loss Contingencies [Line Items]
Ownership interest, percentage		65.00%
Delta Stock Purchase Agreement | Energy Capital Partners
Loss Contingencies [Line Items]
Ownership interest, percentage		35.00%

Income Taxes (Details)

Income Taxes (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Income Tax Disclosure [Abstract]
Current state tax expense	$ 15

Pension and Other Post-Employ73

Pension and Other Post-Employment Benefit Plans (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost benefits earned during period	$ 4	$ 3
Interest cost on projected benefit obligation	5	4
Expected return on plan assets	(6)	(5)
Amortization of prior service credit	0	0
Net periodic benefit cost (gain)	3	2
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Service cost benefits earned during period	0	0
Interest cost on projected benefit obligation	1	1
Expected return on plan assets	(1)	(1)
Amortization of prior service credit	(1)	(1)
Net periodic benefit cost (gain)	$ (1)	$ (1)

Capital Stock (Details)

Capital Stock (Details) - Mandatory Convertible Preferred Stock - USD ($) $ / shares in Units, $ in Millions	Apr. 01, 2016	Mar. 31, 2016	Mar. 31, 2015
Class of Stock [Line Items]
Dividends		$ 5	$ 7
Subsequent Event
Class of Stock [Line Items]
Dividends	$ 5
Dividend declared (in dollars per share)	$ 1.34

Loss Per Share (Details)

Loss Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net loss	$ (10)	$ (181)
Less: Net income attributable to noncontrolling interest	0	(1)
Loss from continuing operations attributable to Dynegy Inc.	(10)	(180)
Less: Dividends on preferred stock	5	5
Loss from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted loss per share	(15)	(185)
Income (Loss) from Continuing Operations Available to Common Stockholders, Basic and Diluted	$ (15)	$ (185)
Basic and diluted shares outstanding (shares)	117	124
Basic and diluted loss per share attributable to Dynegy Inc. common stockholders (in dollars per share)	$ (0.13)	$ (1.49)

Loss Per Share (Anti-Dilutive S

Loss Per Share (Anti-Dilutive Shares - Potentially Dilutive in the Future) (Details) - shares shares in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share	33.8	32.1
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
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	1.2
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
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
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

Condensed Consolidating Finan77

Condensed Consolidating Financial Information (Narrative) (Details) $ in Billions	3 Months Ended
	Mar. 31, 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	$ 5.6

Condensed Consolidating Finan78

Condensed Consolidating Financial Information (Balance Sheets) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 821	$ 505	$ 1,734	$ 1,870
Restricted cash	37	39
Accounts receivable, net	339	402
Inventory	579	597
Other current assets	505	389
Total Current Assets	2,281	1,932
Property, Plant and Equipment, Net	8,242	8,347
Investment in unconsolidated affiliate	185	190
Goodwill	797	797
Other Assets, Noncurrent	203	193
Intercompany note receivable	0	0
Total Assets	11,708	11,459	11,131
Current Liabilities
Accounts payable	243	292
Other current liabilities	620	517
Total Current Liabilities	863	809
Debt, long-term portion	7,304	7,129
Intercompany note payable	0	0
Other long-term liabilities	634	602
Total Liabilities	8,801	8,540
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,909	2,921
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	2,909	2,921
Noncontrolling interest	(2)	(2)
Total Equity	2,907	2,919
Total Liabilities and Equity	11,708	11,459
Eliminations
Current Assets
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0
Accounts receivable, net	(1,644)	(1,730)
Inventory	0	0
Other current assets	(10)	(14)
Total Current Assets	(1,654)	(1,744)
Property, Plant and Equipment, Net	0	0
Investment in unconsolidated affiliate	(12,665)	(13,017)
Goodwill	0	0
Other Assets, Noncurrent	0	0
Intercompany note receivable	(17)	(17)
Total Assets	(14,336)	(14,778)
Current Liabilities
Accounts payable	(1,644)	(1,730)
Other current liabilities	(10)	(14)
Total Current Liabilities	(1,654)	(1,744)
Debt, long-term portion	0	0
Intercompany note payable	(3,059)	(3,059)
Other long-term liabilities	0	0
Total Liabilities	(4,713)	(4,803)
Stockholders’ Equity
Dynegy Stockholders’ Equity	(12,665)	(13,017)
Intercompany note receivable	3,042	3,042
Total Dynegy Stockholders’ Equity	(9,623)	(9,975)
Noncontrolling interest	0	0
Total Equity	(9,623)	(9,975)
Total Liabilities and Equity	(14,336)	(14,778)
Parent
Current Assets
Cash and cash equivalents	639	327	1,438	1,642
Restricted cash	0	0
Accounts receivable, net	539	499
Inventory	0	0
Other current assets	14	13
Total Current Assets	1,192	839
Property, Plant and Equipment, Net	0	0
Investment in unconsolidated affiliate	12,665	13,017
Goodwill	0	0
Other Assets, Noncurrent	8	10
Intercompany note receivable	17	17
Total Assets	13,882	13,883
Current Liabilities
Accounts payable	1,291	1,388
Other current liabilities	193	92
Total Current Liabilities	1,484	1,480
Debt, long-term portion	6,294	6,293
Intercompany note payable	3,042	3,042
Other long-term liabilities	153	147
Total Liabilities	10,973	10,962
Stockholders’ Equity
Dynegy Stockholders’ Equity	2,909	2,921
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	2,909	2,921
Noncontrolling interest	0	0
Total Equity	2,909	2,921
Total Liabilities and Equity	13,882	13,883
Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	80	94	122	54
Restricted cash	0	0
Accounts receivable, net	1,329	1,503
Inventory	309	331
Other current assets	454	335
Total Current Assets	2,172	2,263
Property, Plant and Equipment, Net	7,722	7,813
Investment in unconsolidated affiliate	185	190
Goodwill	797	797
Other Assets, Noncurrent	147	133
Intercompany note receivable	0	0
Total Assets	11,023	11,196
Current Liabilities
Accounts payable	202	238
Other current liabilities	291	277
Total Current Liabilities	493	515
Debt, long-term portion	291	122
Intercompany note payable	0	0
Other long-term liabilities	342	317
Total Liabilities	1,126	954
Stockholders’ Equity
Dynegy Stockholders’ Equity	12,939	13,284
Intercompany note receivable	(3,042)	(3,042)
Total Dynegy Stockholders’ Equity	9,897	10,242
Noncontrolling interest	0	0
Total Equity	9,897	10,242
Total Liabilities and Equity	11,023	11,196
Non-Guarantor Subsidiaries
Current Assets
Cash and cash equivalents	102	84	$ 174	$ 174
Restricted cash	37	39
Accounts receivable, net	115	130
Inventory	270	266
Other current assets	47	55
Total Current Assets	571	574
Property, Plant and Equipment, Net	520	534
Investment in unconsolidated affiliate	0	0
Goodwill	0	0
Other Assets, Noncurrent	48	50
Intercompany note receivable	0	0
Total Assets	1,139	1,158
Current Liabilities
Accounts payable	394	396
Other current liabilities	146	162
Total Current Liabilities	540	558
Debt, long-term portion	719	714
Intercompany note payable	17	17
Other long-term liabilities	139	138
Total Liabilities	1,415	1,427
Stockholders’ Equity
Dynegy Stockholders’ Equity	(274)	(267)
Intercompany note receivable	0	0
Total Dynegy Stockholders’ Equity	(274)	(267)
Noncontrolling interest	(2)	(2)
Total Equity	(276)	(269)
Total Liabilities and Equity	$ 1,139	$ 1,158

Condensed Consolidating Finan79

Condensed Consolidating Financial Information (Operations) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 1,123	$ 632
Cost of sales, excluding depreciation expense	(545)	(377)
Gross margin	578	255
Operating and maintenance expense	(221)	(111)
Depreciation expense	(171)	(64)
General and administrative expense	(37)	(30)
Acquisition and integration costs	(4)	(90)
Operating income (loss)	145	(40)
Equity in earnings from investments in affiliates	0	0
Earnings from unconsolidated investments	2	0
Interest expense	(142)	(136)
Other income and (expense), net	1	(5)
Loss before income taxes	6	(181)
Income tax expense	(16)	0
Net loss	(10)	(181)
Less: Net income attributable to noncontrolling interest	0	(1)
Income (loss) from continuing operations attributable to Dynegy Inc.	(10)	(180)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Revenues	0	0
Cost of sales, excluding depreciation expense	0	0
Gross margin	0	0
Operating and maintenance expense	0	0
Depreciation expense	0	0
General and administrative expense	0	0
Acquisition and integration costs	0	0
Operating income (loss)	0	0
Equity in earnings from investments in affiliates	(118)	147
Earnings from unconsolidated investments	0
Interest expense	0	0
Other income and (expense), net	0	0
Loss before income taxes	(118)	147
Income tax expense	0	0
Net loss	(118)	147
Less: Net income attributable to noncontrolling interest	0	0
Income (loss) from continuing operations attributable to Dynegy Inc.	(118)	147
Parent
Condensed Financial Statements, Captions [Line Items]
Revenues	0	0
Cost of sales, excluding depreciation expense	0	0
Gross margin	0	0
Operating and maintenance expense	0	0
Depreciation expense	0	0
General and administrative expense	(2)	(1)
Acquisition and integration costs	(3)	0
Operating income (loss)	(5)	(1)
Equity in earnings from investments in affiliates	118	(147)
Earnings from unconsolidated investments	0
Interest expense	(124)	(27)
Other income and (expense), net	1	(5)
Loss before income taxes	(10)	(180)
Income tax expense	0	0
Net loss	(10)	(180)
Less: Net income attributable to noncontrolling interest	0	0
Income (loss) from continuing operations attributable to Dynegy Inc.	(10)	(180)
Escrow Issuers
Condensed Financial Statements, Captions [Line Items]
Revenues		0
Cost of sales, excluding depreciation expense		0
Gross margin		0
Operating and maintenance expense		0
Depreciation expense		0
General and administrative expense		0
Acquisition and integration costs		0
Operating income (loss)		0
Equity in earnings from investments in affiliates		0
Interest expense		(93)
Other income and (expense), net		0
Loss before income taxes		(93)
Income tax expense		0
Net loss		(93)
Less: Net income attributable to noncontrolling interest		0
Income (loss) from continuing operations attributable to Dynegy Inc.		(93)
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues	887	413
Cost of sales, excluding depreciation expense	(412)	(239)
Gross margin	475	174
Operating and maintenance expense	(159)	(60)
Depreciation expense	(146)	(56)
General and administrative expense	(28)	(17)
Acquisition and integration costs	(1)	0
Operating income (loss)	141	41
Equity in earnings from investments in affiliates	0	0
Earnings from unconsolidated investments	2
Interest expense	(1)	0
Other income and (expense), net	0	0
Loss before income taxes	142	41
Income tax expense	(16)	0
Net loss	126	41
Less: Net income attributable to noncontrolling interest	0	0
Income (loss) from continuing operations attributable to Dynegy Inc.	126	41
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Revenues	236	219
Cost of sales, excluding depreciation expense	(133)	(138)
Gross margin	103	81
Operating and maintenance expense	(62)	(51)
Depreciation expense	(25)	(8)
General and administrative expense	(7)	(12)
Acquisition and integration costs	0	(90)
Operating income (loss)	9	(80)
Equity in earnings from investments in affiliates	0	0
Earnings from unconsolidated investments	0
Interest expense	(17)	(16)
Other income and (expense), net	0	0
Loss before income taxes	(8)	(96)
Income tax expense	0	0
Net loss	(8)	(96)
Less: Net income attributable to noncontrolling interest	0	(1)
Income (loss) from continuing operations attributable to Dynegy Inc.	$ (8)	$ (95)

Condensed Consolidating Finan80

Condensed Consolidating Financial Information (Comprehensive Income (Loss)) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net loss	$ (10)	$ (181)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(1)	(1)
Other comprehensive loss, net of tax	(1)	(1)
Comprehensive income (loss)	(11)	(182)
Less: Comprehensive loss attributable to noncontrolling interest	0	(1)
Total comprehensive income (loss) attributable to Dynegy Inc.	(11)	(181)
Eliminations
Condensed Financial Statements, Captions [Line Items]
Net loss	(118)	147
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	0	0
Other comprehensive loss, net of tax	0	0
Comprehensive income (loss)	(118)	147
Less: Comprehensive loss attributable to noncontrolling interest	0	0
Total comprehensive income (loss) attributable to Dynegy Inc.	(118)	147
Parent
Condensed Financial Statements, Captions [Line Items]
Net loss	(10)	(180)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	(1)	(1)
Other comprehensive loss, net of tax	(1)	(1)
Comprehensive income (loss)	(11)	(181)
Less: Comprehensive loss attributable to noncontrolling interest	0	0
Total comprehensive income (loss) attributable to Dynegy Inc.	(11)	(181)
Escrow Issuers
Condensed Financial Statements, Captions [Line Items]
Net loss		(93)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero		0
Other comprehensive loss, net of tax		0
Comprehensive income (loss)		(93)
Less: Comprehensive loss attributable to noncontrolling interest		0
Total comprehensive income (loss) attributable to Dynegy Inc.		(93)
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net loss	126	41
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	0	0
Other comprehensive loss, net of tax	0	0
Comprehensive income (loss)	126	41
Less: Comprehensive loss attributable to noncontrolling interest	0	0
Total comprehensive income (loss) attributable to Dynegy Inc.	126	41
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net loss	(8)	(96)
Amounts reclassified from accumulated other comprehensive income:
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero	0	0
Other comprehensive loss, net of tax	0	0
Comprehensive income (loss)	(8)	(96)
Less: Comprehensive loss attributable to noncontrolling interest	0	(1)
Total comprehensive income (loss) attributable to Dynegy Inc.	$ (8)	$ (95)

Condensed Consolidating Finan81

Condensed Consolidating Financial Information (Cash Flow) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$ 191	$ (55)
Capital expenditures	65	40
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers	0	0
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	8	0
Net cash used in investing activities	(57)	(40)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	198	0
Repayments of borrowings	(5)	(25)
Dividends paid	(5)	(7)
Net intercompany transfers	0	0
Interest rate swap settlement payments	(4)	(4)
Other financing	(2)	(5)
Net cash provided by (used in) financing activities	182	(41)
Net increase (decrease) in cash and cash equivalents	316	(136)
Cash and cash equivalents, beginning of period	505	1,870
Cash and cash equivalents, end of period	821	1,734
Eliminations
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	0	0
Capital expenditures	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers	(339)	188
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	0
Net cash used in investing activities	(339)	188
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	0
Repayments of borrowings	0	0
Dividends paid	0	0
Net intercompany transfers	339	(188)
Interest rate swap settlement payments	0	0
Other financing	0	0
Net cash provided by (used in) financing activities	339	(188)
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	(10)	2
Capital expenditures	4	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers	339	(188)
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	0
Net cash used in investing activities	335	(188)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	0
Repayments of borrowings	(2)	(2)
Dividends paid	(5)	(7)
Net intercompany transfers	0	0
Interest rate swap settlement payments	(4)	(4)
Other financing	(2)	(5)
Net cash provided by (used in) financing activities	(13)	(18)
Net increase (decrease) in cash and cash equivalents	312	(204)
Cash and cash equivalents, beginning of period	327	1,642
Cash and cash equivalents, end of period	639	1,438
Escrow Issuers
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities		(94)
Capital expenditures		0
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers		0
Net cash used in investing activities		0
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayments of borrowings		0
Dividends paid		0
Net intercompany transfers		94
Interest rate swap settlement payments		0
Other financing		0
Net cash provided by (used in) financing activities		94
Net increase (decrease) in cash and cash equivalents		0
Cash and cash equivalents, beginning of period		0
Cash and cash equivalents, end of period		0
Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	175	46
Capital expenditures	50	29
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers	0	0
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	8
Net cash used in investing activities	(42)	(29)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	198
Repayments of borrowings	(3)	(23)
Dividends paid	0	0
Net intercompany transfers	(342)	74
Interest rate swap settlement payments	0	0
Other financing	0	0
Net cash provided by (used in) financing activities	(147)	51
Net increase (decrease) in cash and cash equivalents	(14)	68
Cash and cash equivalents, beginning of period	94	54
Cash and cash equivalents, end of period	80	122
Non-Guarantor Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	26	(9)
Capital expenditures	11	11
CASH FLOWS FROM INVESTING ACTIVITIES:
Net intercompany transfers	0	0
Proceeds from Equity Method Investment, Dividends or Distributions, Return of Capital	0
Net cash used in investing activities	(11)	(11)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long term borrowings	0
Repayments of borrowings	0	0
Dividends paid	0	0
Net intercompany transfers	3	20
Interest rate swap settlement payments	0	0
Other financing	0	0
Net cash provided by (used in) financing activities	3	20
Net increase (decrease) in cash and cash equivalents	18	0
Cash and cash equivalents, beginning of period	84	174
Cash and cash equivalents, end of period	$ 102	$ 174

Segment Information (Narrative)

Segment Information (Narrative) (Details)	3 Months Ended
	Mar. 31, 2016segment
Segment Reporting [Abstract]
Number of reportable segments	3

Segment Information (Segment Re

Segment Information (Segment Reporting) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Information
Unaffiliated revenues	$ 1,123	$ 632
Intercompany revenues	0	0
Revenues	1,123	632
Depreciation expense	(171)	(64)
General and administrative expense	(37)	(30)
Acquisition and integration costs	(4)	(90)
Operating income (loss)	145	(40)
Earnings from unconsolidated investments	2	0
Interest expense	(142)	(136)
Other items, net	1	(5)
Income (loss) before income taxes	6	(181)
Income tax expense	(16)	0
Net loss	(10)	(181)
Less: Net income attributable to noncontrolling interest	0	(1)
Net loss attributable to Dynegy Inc.	(10)	(180)
Identifiable assets (domestic)	11,708	11,131	$ 11,459
Investment in unconsolidated affiliate	185
Capital expenditures	(65)	(40)
Operating segments
Segment Information
Investment in unconsolidated affiliate	0
Operating segments | Coal
Segment Information
Unaffiliated revenues	393	154
Intercompany revenues	(13)	(12)
Revenues	380	142
Depreciation expense	(39)	(10)
General and administrative expense	0	0
Acquisition and integration costs	0
Operating income (loss)	54	7
Earnings from unconsolidated investments	0
Interest expense	(1)
Other items, net	0	0
Identifiable assets (domestic)	2,269	1,162
Capital expenditures	(19)	(3)
Operating segments | IPH
Segment Information
Unaffiliated revenues	168	219
Intercompany revenues	(1)	0
Revenues	167	219
Depreciation expense	(9)	(8)
General and administrative expense	0	0
Acquisition and integration costs	0
Operating income (loss)	14	22
Earnings from unconsolidated investments	0
Interest expense	(17)
Other items, net	0	0
Identifiable assets (domestic)	898	1,037
Investment in unconsolidated affiliate	0
Capital expenditures	(11)	(11)
Operating segments | Gas
Segment Information
Unaffiliated revenues	562	259
Intercompany revenues	14	12
Revenues	576	271
Depreciation expense	(122)	(45)
General and administrative expense	0	0
Acquisition and integration costs	0
Operating income (loss)	120	52
Earnings from unconsolidated investments	2
Interest expense	(1)
Other items, net	0	0
Identifiable assets (domestic)	7,815	2,105
Investment in unconsolidated affiliate	185
Capital expenditures	(31)	(24)
Other and Eliminations
Segment Information
Unaffiliated revenues	0	0
Intercompany revenues	0	0
Revenues	0	0
Depreciation expense	(1)	(1)
General and administrative expense	(37)	(30)
Acquisition and integration costs	(4)
Operating income (loss)	(43)	(121)
Earnings from unconsolidated investments	0
Interest expense	(123)
Other items, net	1	(5)
Income tax expense	(16)
Identifiable assets (domestic)	726	6,827
Investment in unconsolidated affiliate	0
Capital expenditures	$ (4)	$ (2)

Subsequent Event (Details)

Subsequent Event (Details) $ in Billions	May. 04, 2016Facilities	Mar. 31, 2016USD ($)
MISO
Subsequent Event [Line Items]
Carrying value of asset | $		$ 1.4
Subsequent Event | Baldwin
Subsequent Event [Line Items]
Number of Facilities	3
Subsequent Event | Baldwin | Facility Closing
Subsequent Event [Line Items]
Number of Facilities	2
Subsequent Event | Newton
Subsequent Event [Line Items]
Number of Facilities	2
Subsequent Event | Newton | Facility Closing
Subsequent Event [Line Items]
Number of Facilities	1