Expand Energy (EXE) 10-K 25 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 09, 2016	Jun. 30, 2015
Document and Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	CHK
Entity Registrant Name	CHESAPEAKE ENERGY CORP
Entity Central Index Key	895,126
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		664,992,714
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 7.4

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 825	$ 4,108
Restricted cash	0	38
Accounts receivable, net	1,129	2,236
Short-term derivative assets ($0 and $16 attributable to our VIE)	366	879
Other current assets	160	207
Total Current Assets	2,480	7,468
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	63,843	58,594
Unproved properties	6,798	9,788
Other property and equipment	2,927	3,083
Total Property and Equipment, at Cost	73,568	71,465
Less: accumulated depreciation, depletion and amortization (($428) and ($251) attributable to our VIE)	(59,365)	(39,043)
Property and equipment held for sale, net	95	93
Total Property and Equipment, Net	14,298	32,515
LONG-TERM ASSETS:
Investments	136	265
Long-term derivative assets	246	6
Other long-term assets	197	497
TOTAL ASSETS	17,357	40,751
CURRENT LIABILITIES:
Accounts payable	944	2,049
Current maturities of long-term debt, net	381	381
Accrued interest	101	150
Short-term derivative liabilities	40	15
Other current liabilities ($8 and $15 attributable to our VIE)	2,219	3,061
Total Current Liabilities	3,685	5,656
LONG-TERM LIABILITIES:
Long-term debt, net	10,354	11,154
Deferred income tax liabilities	0	4,392
Long-term derivative liabilities	60	218
Asset retirement obligations, net of current portion	452	447
Other long-term liabilities	409	679
Total Long-Term Liabilities	11,275	16,890
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,251,515 shares outstanding	3,062	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 664,795,509 and 664,944,232 shares issued	7	7
Paid-in capital	12,403	12,531
Retained earnings (accumulated deficit)	(13,202)	1,483
Accumulated other comprehensive loss	(99)	(143)
Less: treasury stock, at cost; 1,437,724 and 1,614,312 common shares	(33)	(37)
Total Chesapeake Stockholders’ Equity	2,138	16,903
Noncontrolling interests	259	1,302
Total Equity	2,397	18,205
TOTAL LIABILITIES AND EQUITY	$ 17,357	$ 40,751

CONSOLIDATED BALANCE SHEETS (Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Preferred stock, par value (usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (shares)	7,251,515	7,251,515
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,795,509	664,944,232
Treasury stock, shares	1,437,724	1,614,312
VIE, Cash and cash equivalents	$ 825	$ 4,108
VIE, short-term derivative assets	366	879
VIE. proved natural gas and oil properties	63,843	58,594
VIE. accumulated depreciation, depletion and amortization	(59,365)	(39,043)
VIE. other current liabilities	2,219	3,061
Variable Interest Entities, Primary Beneficiary [Member]
VIE, Cash and cash equivalents	1	1
VIE, short-term derivative assets	0	16
VIE. proved natural gas and oil properties	488	488
VIE. accumulated depreciation, depletion and amortization	(428)	(251)
VIE. other current liabilities	$ 8	$ 15

CONSOLIDATED STATEMENTS OF OPER

CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil, natural gas and NGL	$ 5,391	$ 10,354	$ 8,626
Marketing, gathering and compression	7,373	12,225	9,559
Oilfield services	0	546	895
Total Revenues	12,764	23,125	19,080
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,046	1,208	1,159
Oil, natural gas and NGL gathering, processing and transportation	2,119	2,174	1,574
Production taxes	99	232	229
Marketing, gathering and compression	7,130	12,236	9,461
Oilfield services	0	431	736
General and administrative	235	322	457
Restructuring and other termination costs	36	7	248
Provision for legal contingencies	353	234	0
Oil, natural gas and NGL depreciation, depletion and amortization	2,099	2,683	2,589
Depreciation and amortization of other assets	130	232	314
Impairment of oil and natural gas properties	18,238	0	0
Impairments of fixed assets and other	194	88	546
Net (gains) losses on sales of fixed assets	4	(199)	(302)
Total Operating Expenses	31,683	19,648	17,011
INCOME (LOSS) FROM OPERATIONS	(18,919)	3,477	2,069
OTHER INCOME (EXPENSE):
Interest expense	(317)	(89)	(227)
Losses on investments	(96)	(75)	(216)
Impairments of investments	(53)	(5)	(10)
Net gain (loss) on sales of investments	0	67	(7)
Gains (losses) on purchases or exchanges of debt	279	(197)	(193)
Other income	8	22	26
Total Other Expense	(179)	(277)	(627)
INCOME (LOSS) BEFORE INCOME TAXES	(19,098)	3,200	1,442
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(36)	47	22
Deferred income taxes	(4,427)	1,097	526
Total Income Tax Expense (Benefit)	(4,463)	1,144	548
NET INCOME (LOSS)	(14,635)	2,056	894
Net income attributable to noncontrolling interests	(50)	(139)	(170)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(14,685)	1,917	724
Preferred stock dividends	(171)	(171)	(171)
Repurchase of preferred shares of CHK Utica	0	(447)	(69)
Earnings allocated to participating securities	0	(26)	(10)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (14,856)	$ 1,273	$ 474
EARNINGS (LOSS) PER COMMON SHARE:
Earnings Per Share, Basic	$ (22.43)	$ 1.93	$ 0.73
Earnings Per Share, Diluted	(22.43)	1.87	0.73
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0.0875	$ 0.35	$ 0.35
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	662	659	653
Weighted Average Number of Shares Outstanding, Diluted	662	772	653

CONSOLIDATED STATEMENTS OF COMP

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
NET INCOME (LOSS)	$ (14,635)	$ 2,056	$ 894
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $12, $0, and $1	20	1	2
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $15, $14 and $12	24	23	20
Unrealized loss on investments, net of income tax benefit of $0, $0 and ($4)	0	0	(6)
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, ($3) and $3	0	(5)	4
Other Comprehensive Income (Loss)	44	19	20
COMPREHENSIVE INCOME (LOSS)	(14,591)	2,075	914
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(50)	(139)	(170)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ (14,641)	$ 1,936	$ 744

CONSOLIDATED STATEMENTS OF COM6

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $12, $0, and $1	$ 12	$ 0	$ 1
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $15, $14 and $12	15	14	12
Unrealized loss on investments, net of income tax benefit of $0, $0 and ($4)	0	0	(4)
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, ($3) and $3	$ 0	$ (3)	$ 3

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ (14,635)	$ 2,056	$ 894
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	2,229	2,915	2,903
Deferred income tax expense (benefit)	(4,427)	1,097	526
Derivative gains, net	(932)	(1,102)	(71)
Cash receipts (payments) on derivative settlements, net	1,123	(253)	(104)
Stock-based compensation	78	59	98
Impairment of oil and natural gas properties	18,238	0	0
Net (gains) losses on sales of fixed assets	4	(199)	(302)
Impairments of fixed assets and other	175	58	483
Losses on investments	96	75	219
Impairments of investments	53	5	10
Net (gains) losses on sales of investments	0	(67)	7
(Gains) losses on purchases or exchanges of debt	(304)	63	40
Restructuring and other termination costs	(14)	(15)	175
Provision for legal contingencies	340	234	0
Other	244	220	122
(Increase) decrease in accounts receivable and other assets	1,186	(21)	5
Decrease in accounts payable, accrued liabilities and other	(2,220)	(491)	(391)
Net Cash Provided By Operating Activities	1,234	4,634	4,614
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(3,095)	(4,581)	(5,604)
Acquisitions of proved and unproved properties	(533)	(1,311)	(1,032)
Proceeds from divestitures of proved and unproved properties	189	5,813	3,467
Additions to other property and equipment	(143)	(726)	(972)
Proceeds from sales of other property and equipment	89	1,003	922
Additions to investments	(10)	(17)	(44)
Proceeds from sales of investments	0	239	115
Decrease in restricted cash	52	37	177
Other	0	(3)	4
Net Cash Provided By (Used In) Investing Activities	(3,451)	454	(2,967)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	7,406	7,669
Payments on credit facilities borrowings	0	(7,788)	(7,682)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	394	0
Cash paid to purchase debt	(508)	(3,362)	(2,141)
Cash paid for common stock dividends	(118)	(234)	(233)
Cash paid for preferred stock dividends	(171)	(171)	(171)
Cash paid on financing derivatives	0	(53)	(91)
Cash paid to extinguish other financing	0	0	(141)
Cash paid for prepayment of mortgage	0	0	(55)
Distributions to noncontrolling interest owners	(85)	(173)	(215)
Proceeds from sales of noncontrolling interests	0	0	6
Other	(41)	(34)	(105)
Net Cash Used In Financing Activities	(1,066)	(1,817)	(1,097)
Net increase (decrease) in cash and cash equivalents	(3,283)	3,271	550
Cash and cash equivalents, beginning of period	4,108	837	287
Cash and cash equivalents, end of period	825	4,108	837
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	235	96	43
Income taxes paid, net of refunds received	44	10	26
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Repurchase of noncontrolling interest of CHK C-T	(872)	0	0
Divestiture of proved and unproved CHK C-T properties	1,024	0	0
Change in divested proved and unproved properties	35	38	(104)
Change in accrued drilling and completion costs	(148)	(84)	(63)
Change in accrued acquisitions of proved and unproved properties	55	(74)	(1)
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	0	2,966	2,274
Chesapeake Oilfield Operating [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	0	494	0
Cash paid to repurchase noncontrolling interest of CHK C-T	0	(8)	0
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	(143)	0	0
Noncontrolling Interest, Chesapeake Utica L L C [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase preferred shares of CHK Utica	$ 0	$ (1,254)	$ (212)

CONSOLIDATED STATEMENTS OF STOC

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]	Noncontrolling Interest, Chesapeake Utica L L C [Member]
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2012				$ 12,293	$ 437	$ (182)	$ (48)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				162
Exercise of stock options				4
Dividends on common stock				0	(233)
Dividends on preferred stock				0	(171)
Increase (decrease) in tax benefit from stock-based compensation				(13)
Net income (loss) attributable to Chesapeake	$ 724
Spin-off of oilfield services business					0
Repurchase of preferred shares of CHK Utica	(69)
Hedging activity						22
Investment activity						(2)
Purchase of 54,493, 34,678 and 251,403 shares for company benefit plans							(6)
Release of 231,081, 422,395 and 397,098 shares from company benefit plans							8
Chesapeake stockholders’ equity, end of period at Dec. 31, 2013		$ 3,062	$ 7	12,446	688	(162)	(46)	$ 15,995
Stockholders' Equity Attributable to Noncontrolling Interest, Beginning of Period at Dec. 31, 2012									$ 2,327
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	170									$ 75	$ 79
Distributions to noncontrolling interest owners									(215)
Repurchase of preferred shares in noncontrolling interest										0	(143)
Sales of noncontrolling interests									6
Deconsolidation of investments, net									0
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Dec. 31, 2013									2,145
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	18,140
Stock-based compensation				47
Exercise of stock options				23
Dividends on common stock				0	(234)
Dividends on preferred stock				0	(171)
Increase (decrease) in tax benefit from stock-based compensation				15
Net income (loss) attributable to Chesapeake	1,917
Spin-off of oilfield services business	(270)				(270)
Repurchase of preferred shares of CHK Utica	(447)
Hedging activity						24
Investment activity						(5)
Purchase of 54,493, 34,678 and 251,403 shares for company benefit plans							(1)
Release of 231,081, 422,395 and 397,098 shares from company benefit plans							10
Chesapeake stockholders’ equity, end of period at Dec. 31, 2014	16,903	3,062	7	12,531	1,483	(143)	(37)	16,903
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	139									75	43
Distributions to noncontrolling interest owners									(169)
Repurchase of preferred shares in noncontrolling interest										0	(807)
Sales of noncontrolling interests									0
Deconsolidation of investments, net									(6)
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Dec. 31, 2014	1,302								1,302	1,015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	18,205
Stock-based compensation				71
Exercise of stock options				0
Dividends on common stock				(59)	0
Dividends on preferred stock				(128)	0
Increase (decrease) in tax benefit from stock-based compensation				(12)
Net income (loss) attributable to Chesapeake	(14,685)
Spin-off of oilfield services business					0
Repurchase of preferred shares of CHK Utica	0										(447)
Hedging activity						44
Investment activity						0
Purchase of 54,493, 34,678 and 251,403 shares for company benefit plans							(1)
Release of 231,081, 422,395 and 397,098 shares from company benefit plans							5
Chesapeake stockholders’ equity, end of period at Dec. 31, 2015	2,138	$ 3,062	$ 7	$ 12,403	$ (13,202)	$ (99)	$ (33)	$ 2,138
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	50									50
Distributions to noncontrolling interest owners									(78)
Repurchase of preferred shares in noncontrolling interest										$ (1,015)	$ 0
Sales of noncontrolling interests									0
Deconsolidation of investments, net									0
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Dec. 31, 2015	259								$ 259
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	$ 2,397

CONSOLIDATED STATEMENTS OF STO9

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - Treasury Stock - Common [Member] - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Purchase of shares for company benefit plans, shares	54,493	34,678	251,403
Release of shares from company benefit plans, shares	231,081	422,395	397,098

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies (Note)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies Disclosure	Basis of Presentation and Summary of Significant Accounting Policies Description of Company Chesapeake Energy Corporation ("Chesapeake" or the "Company") is an oil and natural gas exploration and production company engaged in the acquisition, exploration and development of properties for the production of oil, natural gas and natural gas liquids (NGL) from underground reservoirs. We also own oil and natural gas marketing and natural gas gathering and compression businesses, and prior to June 30, 2014, an oilfield services business (see Note 13). Our operations are located onshore in the United States. Basis of Presentation The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. Accounting Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates. Risks and Uncertainties Chesapeake’s strategy for 2016 is to focus on improving liquidity and generating cash. Our ability to grow, make capital expenditures and service our debt depends primarily upon the prices we receive for the oil, natural gas and NGL we sell. Substantial expenditures are required to replace reserves, sustain production and fund our business plans. Historically, oil and natural gas prices have been very volatile, and may be subject to wide fluctuations in the future. The recent substantial decline in oil, natural gas and NGL prices has negatively affected the amount of cash we have available for capital expenditures and debt service. Throughout 2015, our capitalized costs of oil and natural gas properties exceeded our full cost ceiling, resulting in a noncash impairment in the carrying value of our oil and natural gas properties of $18.238 billion , which was the primary driver of our net loss in 2015 of $14.635 billion . Based on first-of-the-month index prices over the 11 months ended February 1, 2016, we expect to record additional downward reserve revisions and another material write-down in the carrying value of our oil and natural gas properties in the first quarter of 2016. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters. As of December 31, 2015, we had a cash balance of approximately $825 million and a net working capital deficit of $1.205 billion . Based on our cash balance, forecasted cash flows from operating activities and availability under our revolving credit facility, we expect to be able to fund our planned capital expenditures budget, meet our debt service requirements, and fund our other commitments and obligations for 2016. Oil and natural gas prices have a material impact on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced. If depressed prices persist throughout 2017 and we are unable to restructure or refinance our debt or generate additional liquidity through other actions, this would adversely impact our ability to comply with the financial covenants under our revolving credit facility and to make scheduled debt payments. To the extent that the value of the collateral pledged under the credit facility declines, we may be required to pledge additional collateral in order to maintain the availability of the commitments thereunder. In February 2016, our secured commodity hedging facility was terminated. This facility was collateralized with assets that are now unencumbered and for which we have the flexibility to pledge under our credit facility, if needed. Because of this additional unpledged collateral, we do not expect availability under our revolving credit facility to be materially reduced as a result of the next borrowing base redetermination in the 2016 second quarter. However, our borrowing base may be reduced as a result of oil and natural gas asset sales, a further decline in prices or other factors, some of which are outside of our control. See Note 3 and Note 11 for further discussion of the financial covenants in our revolving credit facility and for discussion of our secured commodity hedging facility, respectively. As of December 31, 2015, we had approximately $9.706 billion principal amount of long-term debt outstanding, of which $381 million matures in March 2016, $1.892 billion matures or can be put to us in 2017 (of which $329 million matures in January 2017 and the remainder matures or can be put to us after the 2017 first quarter) and $878 million matures or can be put to us in 2018. See Note 3 for further discussion of our debt obligations, including principal and carrying amounts of our notes. We expect to draw on our revolving credit facility as early as the 2016 first quarter primarily due to the principal payment to be made to retire our 3.25% Senior Notes due March 2016 and other 2016 first quarter cash needs. We were undrawn on our revolving credit facility as of December 31, 2015. As operator of a substantial portion of our oil and natural gas properties under development, we have significant control and flexibility over the development plan and the associated timing, enabling us to reduce at least a portion of our capital spending as needed. We have reduced our budgeted 2016 capital expenditures, inclusive of capitalized interest, to $1.3 - $1.8 billion, a significant reduction from our 2015 capital spending level of $3.6 billion . We currently plan to use cash flow from operations, cash on hand and our revolving credit facility to fund our capital expenditures during 2016. We expect to generate additional liquidity with proceeds from potential sales of assets that we determine do not fit our strategic priorities. Management continues to review operational plans for 2016 and beyond, which could result in changes to projected capital expenditures and revenues from sales of oil, natural gas and NGL. We closely monitor the amounts and timing of our sources and uses of funds, particularly as they affect our ability to maintain compliance with the financial covenants of our revolving credit facility. Since December 2015, Moody’s Investor Services, Inc. has lowered our senior unsecured credit rating from “ Ba3 ” to “Caa3 ”, and Standard & Poor’s Rating Services has lowered our senior unsecured credit rating from “ BB- ” to “ CC ”. Some of our counterparties have requested or required us to post collateral as financial assurance of our performance under certain contractual arrangements, such as transportation, gathering, processing and hedging agreements. As of February 24 , 2016, we have received requests to post approximately $220 million in collateral, of which we have posted approximately $92 million . We have posted the required collateral, primarily in the form of letters of credit and cash, or are otherwise complying with these contractual requests for collateral. We may be requested or required by other counterparties to post additional collateral in an aggregate amount of approximately $698 million (excluding the supersedeas bond with respect to the 2019 Notes litigation discussed in Note 3), which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business operations with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business commitments and by offsetting amounts that the counterparty owes us. Any posting of additional collateral consisting of cash or letters of credit, which would reduce availability under our credit facility, will negatively impact our liquidity. To supplement our cash flow from operations, we may seek to access the capital markets to refinance a portion of our outstanding indebtedness and improve our li q uidity. We have historically used the debt capital markets, our most efficient method of raising capital, to supplement our liquidity needs. However, access to funds obtained through the high-yield debt market, particularly in the energy sector, has been severely constrained by a variety of market factors that could hinder our ability to raise new capital. We do not believe the high-yield debt market is currently accessible to us at favorable terms, and our accessibility may not improve during 2016. We have taken a number of actions to improve our liquidity. We eliminated quarterly cash dividends on our common stock effective in the 2015 third quarter and suspended payment of dividends on our convertible preferred stock in the 2016 first quarter. In December 2015, we completed private exchanges of approximately $3.9 billion aggregate principal amount of long-term debt for approximately $2.4 billion aggregate principal amount of newly issued 8.00% Senior Secured Second Lien Notes due 2022. In September and December 2015, we amended our $4.0 billion revolving credit facility to provide more flexibility and access to liquidity. In September 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In August 2015, we closed the CHK C-T transactions described in Note 8. We terminated our secured hedge facility in February 2016 and are in the process of securing new hedges with the collateral for our revolving credit facility. The collateral for our recently terminated secured hedge facility is now available for other purposes, including additional collateral under our credit facility. We are also evaluating additional capital exchanges, asset sales, joint ventures and farmouts to increase our liquidity and cash flow. Finally, we recently restructured certain of our gathering agreements to improve our per-unit-gathering rates beginning in 2016, enhance volume growth and satisfy minimum volume commitment obligations. As highlighted above, we have taken measures to mitigate the risks and uncertainties facing us in 2016, including mitigating a portion of our downside exposure to lower commodity prices through derivative contracts, but there can be no assurance that such measures, even if successfully implemented, will satisfy our needs. Further, our ability to generate operating cash flow in the current commodity price environment, sell assets, access capital markets or take any other action to improve our liquidity and manage our debt is subject to the risks discussed above and the other risks and uncertainties that exist in our industry, some of which we may not be able to anticipate at this time or control. If commodity prices remain at depressed levels, or if we fail to complete significant asset sales, access the capital markets on favorable terms or take other actions to improve our liquidity, we may not be able to fund budgeted capital expenditures or meet our debt service requirements in 2017 or beyond. Consolidation Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests. Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any reconsideration events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. Cash and Cash Equivalents and Restricted Cash For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. As of December 31, 2014, our restricted cash consisted of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T). The repurchase and cancellation of the outstanding preferred shares of CHK C-T eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion. Accounts Receivable Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. During 2015, 2014 and 2013, we recognized $4 million , $2 million and $2 million of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 696 $ 1,340 Joint interest 230 691 Other 226 226 Allowance for doubtful accounts (23 ) (21 ) Total accounts receivable, net $ 1,129 $ 2,236 Oil and Natural Gas Properties Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities ). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2015 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 59% by volume and 77% by value of these proved reserves estimates as of December 31, 2015 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis. Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold which can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and the year in which the associated costs were incurred. Year of Acquisition 2015 2014 2013 Prior Total ($ in millions) Leasehold cost $ 121 $ 651 $ 200 $ 4,304 $ 5,276 Exploration cost 68 13 15 58 154 Capitalized interest 331 303 259 475 1,368 Total $ 520 $ 967 $ 474 $ 4,837 $ 6,798 We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2015, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11. Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense. We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred. Other Property and Equipment Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014, as discussed in Note 13. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment for the years ended 2015, 2014 and 2013 and a summary of our other property and equipment held for sale as of December 31, 2015 and 2014. Other property and equipment costs, excluding land, are depreciated on a straight-line basis. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2015, 2014 and 2013, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments. Capitalized Interest Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset. Accounts Payable Included in accounts payable as of December 31, 2015 and 2014 are liabilities of approximately $60 million and $333 million , respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Debt Issuance and Hedging Facility Costs Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility and hedging facility. The remaining unamortized issuance costs as of December 31, 2015 and 2014 totaled $74 million and $130 million , respectively, and are being amortized over the life of the applicable debt instrument or credit facility using the effective interest method. Environmental Remediation Costs Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized. Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations. Revenue Recognition Oil, Natural Gas and NGL Sales . Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties. Natural Gas Imbalances . We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2015 and 2014 was $10 million and $12 million , respectively. Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a gross basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated. Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, rentals, trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Revenues were recognized upon completion stages for our contract drilling, hydraulic fracturing and other oilfield services. Revenue was recognized ratably over the term of the rental for our oilfield rental services. Oilfield trucking services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed. Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments. Derivatives Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively. From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. The changes in fair value of the embedded derivative and the settlements are recognized in our consolidated statements of operations within marketing, gathering and compressio

Earnings Per Share (Note)

Earnings Per Share (Note)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Earnings Per Share Disclosure	Earnings Per Share Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights. Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the years ended December 31, 2015, 2014 and 2013, our contingent convertible senior notes did not have a dilutive effect, and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes. For the years ended December 31, 2015, 2014 and 2013, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. Net Income Adjustments Shares ($ in millions) (in millions) Year Ended December 31, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 86 59 5.75% cumulative convertible preferred stock (series A) $ 63 42 5.00% cumulative convertible preferred stock (series 2005B) $ 10 6 4.50% cumulative convertible preferred stock $ 12 6 Participating securities $ — 1 Year Ended December 31, 2014 Participating securities $ 26 3 Year Ended December 31, 2013 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 86 56 5.75% cumulative convertible preferred stock (series A) $ 63 40 5.00% cumulative convertible preferred stock (series 2005B) $ 10 5 4.50% cumulative convertible preferred stock $ 12 6 Participating securities $ 10 5 For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows: Income (Numerator) Weighted Average Shares (Denominator) Per Share Amount (in millions, except per share data) For the Year Ended December 31, 2014: Basic EPS $ 1,273 659 $ 1.93 Effect of Dilutive Securities: Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: Common shares assumed issued for 5.75% cumulative convertible preferred stock 86 59 Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) 63 42 Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B) 10 6 Common shares assumed issued for 4.50% cumulative convertible preferred stock 12 6 Diluted EPS $ 1,444 772 $ 1.87

Debt (Note)

Debt (Note)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt Disclosure	Debt Our long-term debt consisted of the following as of December 31, 2015 and 2014: December 31, 2015 December 31, 2014 Principal Amount Carrying Principal Carrying ($ in millions) 3.25% senior notes due 2016 $ 381 $ 381 $ 500 $ 500 6.25% euro-denominated senior notes due 2017 (a)(b) 329 329 416 416 6.5% senior notes due 2017 (b) 453 452 660 659 7.25% senior notes due 2018 (b) 538 538 669 669 Floating rate senior notes due 2019 (b) 1,104 1,104 1,500 1,500 6.625% senior notes due 2020 (b) 822 822 1,300 1,300 6.875% senior notes due 2020 (b) 304 303 500 497 6.125% senior notes due 2021 (b) 589 589 1,000 1,000 5.375% senior notes due 2021 (b) 286 286 700 700 4.875% senior notes due 2022 (b) 639 639 1,500 1,500 8.00% senior secured second lien notes due 2022 (b) 2,425 3,584 — — 5.75% senior notes due 2023 (b) 384 384 1,100 1,100 2.75% contingent convertible senior notes due 2035 (c)(d) 2 2 396 381 2.5% contingent convertible senior notes due 2037 (b)(c)(d) 1,110 1,026 1,168 1,024 2.25% contingent convertible senior notes due 2038 (b)(c)(d) 340 289 347 279 Revolving credit facility — — — — Interest rate derivatives (e) — 7 — 10 Total debt, net 9,706 10,735 11,756 11,535 Less current maturities of long-term debt, net (f) (381 ) (381 ) (396 ) (381 ) Total long-term debt, net $ 9,325 $ 10,354 $ 11,360 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.0862 to €1.00 and $1.2098 to €1.00 as of December 31, 2015 and 2014, respectively. See Foreign Currency Derivatives in Note 11 for information on our related foreign currency derivatives. (b) In 2015, a portion of these outstanding senior unsecured notes were exchanged for newly issued 8.00% Senior Secured Second Lien Notes due 2022. See Chesapeake Senior Secured Second Lien Notes and Chesapeake Senior Notes and Contingent Convertible Senior Notes below for further discussion regarding these transactions. (c) The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows: Holders’ Demand Repurchase Rights . The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five , ten , fifteen and twenty years before the maturity date. Optional Conversion by Holders . At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2015, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2016 under this provision. The notes are also convertible, at the holder’s option, during specified five -day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the years ended December 31, 2015, 2014 or 2013. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount. Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture. The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows: Contingent Convertible Senior Notes Holders' Demand Repurchase Dates Common Stock Price Conversion Thresholds Contingent Interest First Payable (if applicable) 2.75% due 2035 November 15, 2020, 2025, 2030 $ 45.02 May 14, 2016 2.5% due 2037 May 15, 2017, 2022, 2027, 2032 $ 59.44 November 14, 2017 2.25% due 2038 December 15, 2018, 2023, 2028, 2033 $ 100.20 June 14, 2019 Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. (d) Discount as of December 31, 2015 and 2014 included $133 million and $224 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (e) See Interest Rate Derivatives in Note 11 for further discussion related to these instruments. (f) As of December 31, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016. As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (c) above, holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercised their demand repurchase rights on November 15, 2015, which required us to repurchase such holders’ notes. Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2015 and thereafter are as follows: Principal Amount of Debt Securities ($ in millions) 2016 $ 381 2017 1,892 2018 878 2019 1,104 2020 1,128 2021 and thereafter 4,323 Total $ 9,706 Chesapeake Senior Secured Second Lien Notes In December 2015, we completed private offers to exchange newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible senior notes (Existing Notes). Approximately $3.929 billion aggregate principal amount of the Existing Notes were exchanged. The Second Lien Notes are secured second lien obligations and are effectively junior to our current and future secured first lien indebtedness, including indebtedness incurred under our revolving credit facility, to the extent of the value of the collateral securing such indebtedness, effectively senior to all of our existing and future unsecured indebtedness, including our outstanding senior notes, to the extent of the value of the collateral, and senior to any future subordinated indebtedness that we may incur. We have the option to redeem the Second Lien Notes, in whole or in part, at specified make-whole or redemption prices. Our Second Lien Notes are governed by an indenture containing covenants that may limit our ability and our subsidiaries’ ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, consolidate, merge or transfer assets and dispose of certain collateral and use proceeds from dispositions of certain collateral. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the Second Lien Notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 22 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. For 10 of the 12 series of Existing Notes (with a carrying value of $3.679 billion ) that were exchanged for $2.219 billion of Second Lien Notes, we accounted for these exchanges as a troubled debt restructuring (“TDR”). For the exchanges classified as TDR, if the future undiscounted cash flows of the newly issued debt are less than the net carrying value of the original debt, a gain is recorded for the difference and the carrying value of the newly issued debt is adjusted to the future undiscounted cash flow amount and no future interest expense is recorded. All future interest payments on the newly issued debt reduce the carrying value. Accordingly, we recognized a gain of $304 million in our consolidated statement of operations, and the remaining reduction in principal amount of Existing Notes of $1.159 billion is included in the carrying value of our Second Lien Notes. As a result, our reported interest expense will be significantly less than the contractual interest payments throughout the term of the Second Lien Notes. For the remaining TDR exchanges, where the future undiscounted cash flows are greater than the net carrying value of the original debt, no gain is recognized and a new effective interest rate is established. For the other two series of Existing Notes that were exchanged and did not qualify as a TDR, we accounted for these exchanges as either a modification or extinguishment. Direct costs incurred of $30 million related to the notes exchange were expensed and are included within gains (losses) on purchases or exchanges of debt in our consolidated statement of operations. Chesapeake Senior Notes and Contingent Convertible Senior Notes The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect wholly owned subsidiaries. See Note 22 for consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. Indentures for the Second Lien Notes, senior notes and contingent convertible senior notes have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million , depending on the indenture. We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86% , 8.0% and 8.0% , respectively. During 2015, as required by the terms of the indenture for our 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), the holders were provided the option to require us to purchase on November 15, 2015, all or a portion of the holders’ 2035 Notes at par plus accrued and unpaid interest up to, but excluding, November 15, 2015. On November 16, 2015, we paid an aggregate of approximately $394 million to purchase all of the 2035 Notes that were tendered and not withdrawn. An aggregate of $2 million principal amount of the 2035 Notes remains outstanding as of December 31, 2015 . During 2015, we repurchased in the open market approximately $119 million aggregate principal amount of our 3.25% Senior Notes due 2016 for cash. We recorded a gain of approximately $5 million associated with the repurchase. During 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion . We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges. During 2013, we issued $2.3 billion in aggregate principal amount of senior notes at par. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our revolving credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during 2013. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During 2013, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, our redemption of the 2019 Notes has been the subject of litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013. In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 2019 Notes. The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee moved the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest from the redemption date. On March 20, 2015, the Company filed its opposition to the Trustee’s motion and cross-moved for a judgment requiring the Company to pay restitution in an amount that would disgorge the benefit the Company achieved from refinancing the 2019 Notes in 2013 and that would return the parties to the economic positions they would have been in if the par redemption had never taken place. On July 10, 2015, the District Court granted the Trustee’s motion and denied the Company’s cross-motion and entered an amended judgment on July 17, 2015 awarding the Trustee $380 million plus prejudgment interest in the amount of $59 million . The Company filed a notice of appeal on July 27, 2015 and posted a supersedeas bond to stay execution of the judgment while appellate proceedings are pending. Revolving Credit Facility In September and December 2015, we amended our $4.0 billion senior revolving credit facility dated December 15, 2014 and maturing December 2019, which is used for general corporate purposes. Pursuant to the amended credit agreement, we are required to secure our obligations under the facility with liens on certain of our oil and natural gas properties, with such liens to be released upon the satisfaction of specific conditions. The amended credit facility provides that, while the obligations are required to be secured, (i) we have the right to incur junior lien indebtedness of up to $4.0 billion; (ii) our use of the facility will be subject to a borrowing base; (iii) the rate of interest on outstanding loans, as well as fees on undrawn commitments, will vary based on the percentage of the borrowing base used, rather than on our credit ratings; (iv) the total leverage ratio covenant will be suspended; and (v) the credit facility will be subject to a first lien secured leverage ratio and an interest rate coverage ratio (as described below). The permitted junior lien debt basket of $4.0 billion may be increased upon the satisfaction of certain conditions, including the following: (i) after giving effect to all debt secured by such junior liens and the uses of such debt in retirement of other indebtedness, our net annual cash interest expense would increase by no more than $75 million, and (ii) we have exchanged debt secured by such junior liens for more than $2.0 billion aggregate principal amount of outstanding senior notes with maturities or initial put dates in 2017 through 2019. The September amendment sets the borrowing base at $4.0 billion. The total commitments under the credit facility remain at $4.0 billion, subject to reduction in connection with issuances of junior lien indebtedness by us after April 15, 2016, the date of the first borrowing base redetermination. No adjustment to the total commitment has occurred or will occur for any junior lien indebtedness issuance that occurs before April 15, 2016. As of December 31, 2015 , we had no outstanding borrowings under the facility and had used $16 million of the facility for various letters of credit. While obligations under our credit facility are required to be secured, revolving loans under the amended credit facility will bear interest, at our election, at either (i) a fluctuating rate per annum equal to the highest of (a) the federal funds effective rate plus 0.5% , (b) the administrative agent’s prime rate or (c) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), or (ii) a LIBOR rate (LIBOR loans), in each case plus a margin based on the percentage of the borrowing base used (currently 1.0% per annum for ABR loans and 2.0% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates, together with a requirement that we maintain, as of the last day of each fiscal quarter, a net debt to capitalization ratio (as defined in the amended credit agreement) that does not exceed 65%. While it is required to be secured by a portion of our oil and natural gas properties, the amended credit facility requires us to maintain, as of the last day of each fiscal quarter (i) a first lien secured leverage ratio (as defined in the amended credit agreement) of 3.5 to 1.0 through 2017 and no more than 3.0 to 1.0 thereafter, and (ii) an interest rate coverage ratio (as defined in the amended credit agreement) of at least 1.1 to 1.0 through the first quarter of 2017, increasing to 1.25 to 1.0 by the end of 2017. Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The amended credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more ; bankruptcy; judgments involving liability of $125 million or more that are not paid ; and ERISA events . Many events of default are subject to customary notice and cure periods. Term Loan In November 2012, we established an unsecured five -year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion . The term loan provided that it could be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The maturity date of the term loan was December 2, 2017. In 2014, we used a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. We recorded a loss of $90 million , consisting of $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges, in connection with the termination. Spin-Off Debt Transactions On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary Chesapeake Oilfield Operating, L.L.C. (COO), into the independent, publicly traded company Seventy Seven Energy Inc. (SSE). In 2014, COO or its subsidiaries completed the following debt transactions: • Entered into a five -year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility. • Entered into a $400 million seven -year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s then-existing credit facility. • Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes. All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 13 for further discussion of the spin-off. Fair Value of Debt We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which would include borrowings under our revolving credit facility (which was undrawn as of December 31, 2015 and 2014), is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. December 31, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 381 $ 366 $ 381 $ 396 Long-term debt (Level 1) $ 10,347 $ 3,735 $ 11,144 $ 11,656

Contingencies and Commitments (

Contingencies and Commitments (Note)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Legal Matters and Contingencies	Contingencies Litigation and Regulatory Proceedings The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred. Regulatory Proceedings. The Company has received, from the U.S. Department of Justice (DOJ) and certain state governmental agencies and authorities, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state antitrust laws relating to our purchase and lease of oil and natural gas rights in various states. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ, U.S. Postal Service and state agency representatives and continues to respond to such subpoenas and demands. Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we accrued a loss contingency of $100 million for this matter in 2014, and we accrued an additional $339 million in 2015 as a result of the judgment on remand entered on July 17, 2015. The loss contingency associated with this matter is fully accrued as of December 31, 2015. Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their oil and natural gas interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these failure-to-close cases in various courts, has settled and resolved other such cases and disputes and believes that its remaining loss exposure for these claims will not have a material adverse effect on the Company’s financial position, results of operations or cash flows. Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. On April 8, 2015, Chesapeake obtained a transfer order from the Texas Multidistrict Litigation Panel to transfer a substantial portion of these lawsuits filed since June 2014 to the 348th District Court of Tarrant County for pre-trial purposes. On February 12, 2016, Chesapeake filed a motion to change venue for several other lawsuits to Harris County, or alternatively, to Tarrant County. These lawsuits, which primarily relate to the Barnett Shale, generally allege that Chesapeake underpaid royalties by making improper deductions and using incorrect production volumes. In addition to allegations of breach of contract, a number of these lawsuits allege fraud, conspiracy, joint venture and antitrust violations by Chesapeake. Chesapeake expects that additional lawsuits will be filed by new plaintiffs making similar allegations. The lawsuits seek direct damages in varying amounts, together with exemplary damages, attorneys’ fees, costs and interest. On December 9, 2015, the Commonwealth of Pennsylvania, by the Office of Attorney General, filed a lawsuit in the Bradford County Court of Common Pleas related to royalty underpayment and lease acquisition and accounting practices with respect to properties in Pennsylvania. The lawsuit, which primarily relates to the Marcellus Shale and Utica Shale, alleges that Chesapeake violated the Pennsylvania Unfair Trade Practices and Consumer Protection Law (UTPCPL) by making improper deductions and entering into arrangements with affiliates that resulted in underpayment of royalties. The lawsuit seeks statutory restitution, civil penalties and costs, as well as temporary injunction from exploration and drilling activities in Pennsylvania until restitution, penalties and costs have been paid and permanent injunction from further violations of the UTPCPL. On February 8, 2016, the Office of Attorney General amended the complaint to, among other things, add an additional UTPCPL claim and antitrust claim alleging that a joint exploration agreement to which Chesapeake is a party established unlawful market allocation for the acquisition of leases. Putative statewide class actions in Pennsylvania and Ohio and purported class arbitrations in Pennsylvania have been filed on behalf of royalty owners asserting various claims for damages related to alleged underpayment of royalties as a result of the Company’s divestiture of substantially all of its midstream business and most of its gathering assets in 2012 and 2013. These cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act and one of the cases includes claims of intentional interference with contractual relations and violations of antitrust laws related to purported markets for gas mineral rights, operating rights and gas gathering sources. We have not accrued a loss contingency for any of the Pennsylvania and Ohio matters seeking class certification. We believe losses are reasonably possible in certain of the pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years. Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Environmental Contingencies The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property
Commitments Contingencies and Guarantees	Commitments Operating Leases Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below. December 31, 2015 ($ in millions) 2016 $ 4 2017 2 2018 2 2019 1 Total $ 9 Lease expense for the years ended December 31, 2015, 2014 and 2013 was $7 million , $33 million and $158 million , respectively. Lease expense decreased significantly in 2015 and 2014 compared to 2013 primarily due to the repurchase of all rigs and compressors previously sold under long-term sale-leaseback arrangements. Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of oil, natural gas and NGL to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying consolidated balance sheets; however, they are reflected as operating expenses in our proved reserves estimates. The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below. December 31, ($ in millions) 2016 $ 1,932 2017 1,944 2018 1,742 2019 1,443 2020 1,111 2021 – 2099 5,793 Total $ 13,965 In addition, we have entered into long-term agreements for certain natural gas gathering and related services within specified acreage dedication areas in exchange for cost-of-service based fees redetermined annually or tiered fees based on volumes delivered relative to scheduled volumes. Future gathering fees vary with the applicable agreement. One of these agreements in the Anadarko Basin in northwestern Oklahoma and the Texas panhandle contains cost-of-service based fees that are redetermined annually through 2019. The annual upward or downward fee adjustment for this contract is capped at 15% of the then-current fees at the time of redetermination. To the extent the actual rate of return on capital expended by the counterparty over the term of the agreement differs from the applicable rate of return, a payment is due to (from) the midstream service company. Drilling Contracts We have contracts with various drilling contractors to utilize drilling services with terms ranging from three months to three years at market-based pricing. These commitments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below. December 31, ($ in millions) 2016 $ 160 2017 114 2018 6 Total $ 280 Pressure Pumping Contracts In connection with the spin-off of our oilfield services business in June 2014, we entered into an agreement with a subsidiary of SSE for pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven , five and three pressure pumping crews in years one , two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. As of December 31, 2015 , the aggregate undiscounted minimum future payments under this agreement are detailed below. December 31, 2015 ($ in millions) 2016 $ 122 2017 64 Total $ 186 Drilling Commitments We have committed to drill wells for the benefit of Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 8 for discussion of this commitment. Oil, Natural Gas and NGL Purchase Commitments We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions. Net Acreage Maintenance Commitments Under the terms of our Barnett and Utica Shale joint venture agreements with Total S.A. (see Joint Ventures in Note 12), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates. In 2015, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge, which is included in impairments of fixed assets and other in our consolidated statement of operations. Other Commitments As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance. In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and natural gas properties, our purchase and sale agreements may require the return of a portion of the proceeds we receive as a result of uncured title defects. Certain of our oil and natural gas properties are burdened by non-operating interests such as royalty and overriding royalty interests, including overriding royalty interests sold through our VPP transactions. As the holder of the working interest from which these interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to these interests. See Volumetric Production Payments in Note 12 for further discussion of our VPP transactions. While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.

Other Liabilities (Note)

Other Liabilities (Note)	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other Liabilities Disclosure	Other Liabilities Other current liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) Revenues and royalties due others $ 500 $ 1,176 Accrued drilling and production costs 212 385 Joint interest prepayments received 169 189 Accrued compensation and benefits 264 344 Other accrued taxes 21 55 Accrued dividends — 101 Bank of New York Mellon legal accrual 439 100 Oklahoma royalty settlement — 119 Minimum gathering volume commitment (a) 201 141 Other 413 451 Total other current liabilities $ 2,219 $ 3,061 ____________________________________________ (a) Minimum gathering volume commitments are presented on a gross basis. We have recorded receivables from certain of our working interest partners for their proportionate share of the liabilities of $27 million and $21 million as of December 31, 2015 and 2014, respectively. Other long-term liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 190 $ 220 CHK C-T ORRI conveyance obligation (b) — 135 Financing obligations 29 30 Unrecognized tax benefits 64 45 Other 126 249 Total other long-term liabilities $ 409 $ 679 ____________________________________________ (a) $21 million and $14 million of the total $211 million and $234 million obligations are recorded in other current liabilities as of December 31, 2015 and 2014, respectively. See Noncontrolling Interests in Note 8 for further discussion of the conveyance obligation. (b) $23 million of the total $158 million obligation is recorded in other current liabilities as of December 31, 2014. In 2015, we sold the oil and natural gas properties held by CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and eliminated our ORRI obligation attributable to CHK C-T. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

Income Taxes (Note)

Income Taxes (Note)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Income Taxes The components of the income tax provision (benefit) for each of the periods presented below are as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Current Federal $ — $ — $ — State (36 ) 47 22 Current Income Taxes (36 ) 47 22 Deferred Federal (4,385 ) 1,115 502 State (42 ) (18 ) 24 Deferred Income Taxes (4,427 ) 1,097 526 Total $ (4,463 ) $ 1,144 $ 548 The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons: Years Ended December 31, 2015 2014 2013 ($ in millions) Income tax expense (benefit) at the federal statutory rate (35%) $ (6,684 ) $ 1,120 $ 505 State income taxes (net of federal income tax benefit) (406 ) 68 88 Remeasurement of state deferred tax liabilities — (114 ) (38 ) Change in valuation allowance 2,727 74 (12 ) Other (100 ) (4 ) 5 Total $ (4,463 ) $ 1,144 $ 548 We reassessed the realizability of our deferred tax assets given the decline in commodity prices and recorded a $2.727 billion tax expense for the year ended December 31, 2015 for the increase in our valuation allowance. Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows: Years Ended December 31, 2015 2014 ($ in millions) Deferred tax liabilities: Property, plant and equipment $ — $ (3,829 ) Volumetric production payments (802 ) (1,023 ) Carrying value of debt — (443 ) Derivative instruments (294 ) (428 ) Other (74 ) (114 ) Deferred tax liabilities (1,170 ) (5,837 ) Deferred tax assets: Property, plant and equipment 1,140 — Net operating loss carryforwards (carrybacks) 1,556 945 Carrying value of debt 535 — Asset retirement obligations 174 165 Investments 132 84 Accrued liabilities 332 239 Other 250 234 Deferred tax assets 4,119 1,667 Valuation allowance (2,949 ) (222 ) Net deferred tax assets 1,170 1,445 Net deferred tax assets (liabilities) $ — $ (4,392 ) Reflected in accompanying balance sheets as: Non-current deferred income tax liability $ — $ (4,392 ) Total $ — $ (4,392 ) In connection with the exchange of our 8.00% Senior Secured Second Lien Notes due 2022, for Existing Notes, we recognized approximately $2.8 billion of cancellation of indebtedness income for tax purposes. The income from the cancellation of indebtedness is included in the deferred tax asset on property, plant and equipment. As of December 31, 2015, Chesapeake had federal income tax NOL carryforwards of approximately $3.2 billion and state NOL carryforwards of approximately $9.5 billion which excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under U.S. GAAP. The associated deferred tax assets related to these NOL carryforwards were $1.107 billion and $449 million . Additionally, we had $31 million of alternative minimum tax (AMT) NOL carryforwards, net of unrecognized tax benefits, available as a deduction against future AMT income. The NOL carryforwards expire from 2031 through 2035. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2015 and 2014, we had deferred tax assets of $4.119 billion and $1.667 billion , respectively, upon which we had a valuation allowance of $2.949 billion and $222 million , respectively. The net change in the valuation allowance of $2.727 billion for both federal and state deferred tax assets is reflected as a component of income tax expense. A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. We believe it is more likely than not that these deferred tax assets will not be realized. Management assesses the available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit the use of deferred tax assets. A significant piece of objective negative evidence evaluated is the cumulative loss incurred over the three-year period ending December 31, 2015. Such objective negative evidence limits the ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth. Deferred tax assets relating to tax benefits of employee share-based compensation have been reduced for stock options exercised and restricted stock that vested in periods in which Chesapeake was in a net operating loss (NOL) position. Some exercises and vestings result in tax deductions in excess of previously recorded benefits based on the stock option or restricted stock value at the time of grant (windfalls). Although these additional tax benefits or windfalls are reflected in NOL carryforwards in the tax return, the additional tax benefit associated with the windfalls is not recognized until the deduction reduces taxes payable pursuant to accounting for stock compensation under U.S. GAAP. Accordingly, since the tax benefit does not reduce Chesapeake's current taxes payable due to NOL carryforwards, these windfall tax benefits are not reflected in Chesapeake's NOLs in deferred tax assets. Windfalls included in NOL carryforwards but not reflected in deferred tax assets as of December 31, 2015 totaled $19 million . Any shortfalls resulting from tax deductions that were less than the previously recorded benefits were recorded as reductions to additional paid-in capital. The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended. The utilization of these carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake. As of December 31, 2015, we do not believe that an ownership change has occurred that would limit the carryforwards. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs. Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2015 and 2014, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $280 million and $303 million , respectively. Of the 2015 amount, $44 million is related to state tax liabilities while the remainder is related to NOL carryforwards. Of the 2014 amount, $23 million and $17 million are related to AMT and state tax liabilities, respectively, while the remainder is related to NOL carryforwards. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2015 and 2014, we had accrued liabilities of $20 million and $5 million , respectively, for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2015 2014 2013 ($ in millions) Unrecognized tax benefits at beginning of period $ 303 $ 644 $ 599 Additions based on tax positions related to the current year 27 13 15 Additions to tax positions of prior years — — 30 Reductions to tax positions of prior years (50 ) (354 ) — Unrecognized tax benefits at end of period $ 280 $ 303 $ 644 Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2010 through 2013 . The 2010 through 2015 years and the 2007 through 2015 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions, respectively.

Related Party Transactions (Not

Related Party Transactions (Note)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions Disclosure	Related Party Transactions Our equity method investees are considered related parties. During 2015, 2014 and 2013, we had the following transactions with our equity method investees: Years Ended December 31, 2015 2014 2013 ($ in millions) Sales (a) $ — $ — $ 666 Services (b) $ 65 $ 220 $ 397 ___________________________________________ (a) In 2013, Chesapeake sold produced gas to our 30% -owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014. (b) Hydraulic fracturing and other services are provided to us by FTS International, Inc. in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.

Equity (Note)

Equity (Note)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Stockholders' Equity Note Disclosure	Equity Common Stock The following is a summary of the changes in our common shares issued for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 (in thousands) Shares issued as of January 1 664,944 666,192 666,468 Restricted stock issuances (net of forfeitures and cancellations) (a) (163 ) (2,529 ) (599 ) Stock option exercises 15 1,281 323 Shares issued as of December 31 664,796 664,944 666,192 ___________________________________________ (a) The amount for 2014 reflects forfeitures upon the June 2014 spin-off of our oilfield services business. Preferred Stock Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2015: Preferred Stock Series Issue Date Liquidation Preference per Share Holder's Conversion Right Conversion Rate Conversion Price Company's Conversion Right From Company's Market Conversion Trigger (a) 5.75% cumulative convertible non-voting May and June 2010 $ 1,000 Any time 39.6526 $ 25.2190 May 17, 2015 $ 32.7847 5.75% (series A) cumulative convertible non-voting May 2010 $ 1,000 Any time 38.3186 $ 26.0970 May 17, 2015 $ 33.9261 4.50% cumulative convertible September 2005 $ 100 Any time 2.4561 $ 40.7152 September 15, 2010 $ 52.9298 5.00% cumulative convertible (series 2005B) November 2005 $ 100 Any time 2.7745 $ 36.0431 November 15, 2010 $ 46.8560 ___________________________________________ (a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding. The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2015, 2014 and 2013: 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2015, 2014 and 2013 and shares outstanding as of December 31, 2015, 2014 and 2013 1,497 1,100 2,559 2,096 Dividends Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, dividend declarations are accounted for as a reduction to paid-in capital. In July 2015, our Board of Directors determined to eliminate quarterly cash dividends on our common stock. In January 2016, we announced that we were suspending payment of dividends on each series of our outstanding convertible preferred stock. Suspension of the dividends did not constitute an event of default under our revolving credit facility or bond indentures. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash. Accumulated Other Comprehensive Income (Loss) For the years ended December 31, 2015 and 2014, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Investments Net Change ($ in millions) Balance, December 31, 2014 $ (143 ) $ — $ (143 ) Other comprehensive income before reclassifications 20 — 20 Amounts reclassified from accumulated other comprehensive income 24 — 24 Net other comprehensive income 44 — 44 Balance, December 31, 2015 $ (99 ) $ — $ (99 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 1 — 1 Amounts reclassified from accumulated other comprehensive income 23 (5 ) 18 Net other comprehensive income 24 (5 ) 19 Balance, December 31, 2014 $ (143 ) $ — $ (143 ) For the years ended December 31, 2015 and 2014, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below. Details About Accumulated Other Comprehensive Income (Loss) Components Affected Line Item in the Statement Where Net Income is Presented Amounts Reclassified ($ in millions) Year Ended December 31, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 23 Foreign currency derivative Gain (loss) on purchases or exchanges of debt 1 Total reclassifications for the period, net of tax $ 24 Year Ended December 31, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 23 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 18 Noncontrolling Interests Cleveland Tonkawa Financial Transaction. We formed CHK C-T in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum cumulative total of 300 net wells. We ultimately drilled and completed 190 net wells, and the drilling commitment was suspended in January 2015. During 2015, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC (FourPoint) and immediately used the consideration received, plus other cash it had on hand, to repurchase and cancel all of the outstanding preferred shares in CHK C-T. Chesapeake is responsible for post-closing adjustments to the purchase price and has certain indemnity obligations in connection with the sale to FourPoint. In connection with the repurchase and cancellation of the CHK C-T preferred stock and related agreements with the CHK C-T investors, we eliminated quarterly preferred dividend payments and all related future drilling and ORRI commitments attributable to CHK C-T. The sale of the oil and natural gas properties was accounted for as a reduction of capitalized costs with no gain or loss recognized. As of December 31, 2014, $1.015 billion of noncontrolling interests on our consolidated balance sheets was attributable to CHK C-T. For 2015, 2014 and 2013, income of $50 million , $75 million and $75 million , respectively, was attributable to the noncontrolling interests of CHK C-T. Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold. In July 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion , or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired was reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold. The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150 -acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. As of December 31, 2015 , we had drilled 499 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest was reduced accordingly. We met our ORRI conveyance commitments as of December 31, 2013, 2014 and 2015. In 2014 and 2013, income of approximately $43 million and $79 million , respectively, was attributable to the noncontrolling interests of CHK Utica. Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding. In connection with the Trust’s initial public offering, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 then-producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres ( 29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill and complete, or cause to be drilled and completed, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling and completion of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount recoverable by the Trust under the lien was limited to $263 million initially and is proportionately reduced as we fulfill our drilling obligation over time. As of December 31, 2015 , we had drilled and completed or caused to be drilled and completed approximately 106 development wells, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $27 million . The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units is reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent 14 quarters. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold is to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through December 31, 2015 , no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After this time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis. For the years ended December 31, 2015, 2014 and 2013, the Trust declared and paid the following distributions: Production Period Distribution Date Cash Distribution per Common Unit Cash Distribution per Subordinated Unit June 2015 – August 2015 November 30, 2015 $ 0.3232 $ — March 2015 – May 2015 August 31, 2015 $ 0.3579 $ — December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — June 2014 – August 2014 December 1, 2014 $ 0.5079 $ — March 2014 – May 2014 August 29, 2014 $ 0.5796 $ — December 2013 – February 2014 May 30, 2014 $ 0.6454 $ — September 2013 – November 2013 March 3, 2014 $ 0.6624 $ — June 2013 – August 2013 November 29, 2013 $ 0.6671 $ — March 2013 – May 2013 August 29, 2013 $ 0.6900 $ 0.1432 December 2012 – February 2013 May 31, 2013 $ 0.6900 $ 0.3010 September 2012 – November 2012 March 1, 2013 $ 0.6700 $ 0.3772 We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our consolidated financial statements. As of December 31, 2015 and 2014, approximately $259 million and $287 million , respectively, of noncontrolling interests on our consolidated balance sheets were attributable to the Trust. In 2015 we had net income of a nominal amount and in 2014 and 2013 we had net income of $24 million and $20 million , respectively, attributable to the Trust’s noncontrolling interests in our consolidated statements of operations as income. See Note 15 for further discussion of VIEs.

Share-Based Compensation (Note)

Share-Based Compensation (Note)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments	Share-Based Compensation Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards. In connection with the spin-off of our oilfield services business on June 30, 2014, and pursuant to the terms of our share-based compensation plans and the employee matters agreement between Chesapeake and Seventy Seven Energy Inc., unexercised stock options and unvested restricted stock were modified as of the date of the spin-off. The modifications were designed to ensure that the value of each award of unexercised stock options and unvested restricted stock did not change as a result of the spin-off. The number of stock options and number of shares of restricted stock reported below have been adjusted to reflect modifications on the spin-off date. Share-Based Compensation Plans 2014 Long Term Incentive Plan . Our 2014 Long Term Incentive Plan (2014 LTIP), which is administered by the Compensation Committee of our Board of Directors, became effective on June 13, 2014 after it was approved by shareholders at our 2014 Annual Meeting. The 2014 LTIP replaced our Amended and Restated Long Term Incentive Plan (2005 LTIP) which was adopted in 2005. The 2014 LTIP provides for up to 36,600,000 shares of common stock that may be issued as long-term incentive compensation to our employees and non-employee directors; provided, however, that the 2014 LTIP uses a fungible share pool under which (i) each share issued pursuant to a stock option or stock appreciation right (SAR) reduces the number of shares available under the 2014 LTIP by 1.0 share; (ii) each share issued pursuant to awards other than options and SARs reduces the number of shares available by 2.12 shares; and (iii) PSUs and other performance awards which are payable solely in cash are not counted against the aggregate number of shares issuable. In addition, the 2014 LTIP prohibits the reuse of shares withheld or delivered to satisfy the exercise price of, or to satisfy tax withholding requirements for, an option or SAR. The 2014 LTIP also prohibits “net share counting” upon the exercise of options or SARs. The 2014 LTIP authorizes the issuance of the following types of awards: (i) nonqualified and incentive stock options; (ii) SARs; (iii) restricted stock; (iv) performance awards, including PSUs; and (v) other stock-based awards. For both stock options and SARs, the exercise price may not be less than the fair market value of our common stock on the date of grant and the maximum exercise period may not exceed ten years from the date of grant. Awards granted under the plan vest at specified dates and/or upon the satisfaction of certain performance or other criteria, as determined by the Compensation Committee. In 2015, we issued 225,630 and 5,440,420 shares of restricted stock, net of forfeitures, to non-employee directors and employees, respectively, under the 2014 LTIP. In 2014, we issued 50,771 and 272,289 shares of restricted stock net of forfeitures, to non-employee directors and employees, respectively, under the 2014 LTIP. Additionally in 2015, we issued options to purchase 1,208,185 shares of common stock to employees under the 2014 LTIP. As of December 31, 2015, 35,350,862 shares of common stock remained issuable under the 2014 LTIP. 2003 Stock Award Plan for Non-Employee Directors . Under Chesapeake's 2003 Stock Award Plan for Non-Employee Directors (2003 Non-Employee Director Plan), a maximum of 10,000 shares of Chesapeake's common stock is awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares issued may not exceed 250,000 shares. The plan was approved by our shareholders. We issued 10,000 , 10,000 and 20,000 shares of common stock to newly appointed non-employee directors under the 2003 Non-Employee Director Plan in 2015, 2014 and 2013, respectively. In November 2015, our Board of Directors terminated the 2003 Non-Employee Director Plan. Equity-Classified Awards Restricted Stock. We grant restricted stock units to employees and non-employee directors. Prior to 2014, we also granted restricted stock awards as equity compensation. We refer to both types of awards as restricted stock. Restricted stock vests over a minimum of three years and the holder receives dividends, if paid, on unvested shares. A summary of the changes in unvested restricted stock during 2015, 2014 and 2013 is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2015 10,091 $ 21.20 Granted 7,095 $ 13.90 Vested (4,157 ) $ 21.70 Forfeited (2,574 ) $ 16.98 Unvested restricted stock as of December 31, 2015 10,455 $ 17.31 Unvested restricted stock as of January 1, 2014 13,400 $ 23.38 Granted 5,049 $ 25.92 Vested (4,803 ) $ 27.17 Forfeited (3,555 ) $ 28.09 Unvested restricted stock as of December 31, 2014 10,091 $ 21.20 Unvested restricted stock as of January 1, 2013 18,899 $ 23.72 Granted 9,189 $ 19.68 Vested (12,897 ) $ 21.32 Forfeited (1,791 ) $ 22.86 Unvested restricted stock as of December 31, 2013 13,400 $ 23.38 The aggregate intrinsic value of restricted stock that vested during 2015 was approximately $59 million based on the stock price at the time of vesting. As of December 31, 2015 , there was approximately $109 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 1.85 years. The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the Company’s common stock at the date of vesting and the date of grant. During 2015 and 2013, we recognized reductions in tax benefits related to restricted stock of $12 million and $14 million , respectively. During 2014, we recognized an excess tax benefit related to restricted stock of $12 million . Each adjustment was recorded to additional paid-in capital and deferred income taxes. Stock Options. In 2015, 2014 and 2013, we granted members of senior management stock options that vest ratably over a three -year period. In January 2013, we also granted retention awards of stock options to certain officers that vest one-third on each of the third , fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options expire seven to ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2015: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 % The following table provides information related to stock option activity for 2015, 2014 and 2013: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding at January 1, 2015 4,599 $ 19.55 7.03 $ 5 Granted 1,208 $ 18.37 Exercised (14 ) $ 18.13 $ — Expired (416 ) $ 18.46 Forfeited — $ — Outstanding at December 31, 2015 5,377 $ 19.37 5.80 $ — Exercisable at December 31, 2015 2,045 $ 19.61 5.07 $ — Outstanding at January 1, 2014 5,268 $ 19.28 6.66 $ 41 Granted 994 $ 24.43 Exercised (1,322 ) $ 18.71 $ 11 Expired (28 ) $ 18.97 Forfeited (313 ) $ 21.05 Outstanding at December 31, 2014 4,599 $ 19.55 7.03 $ 5 Exercisable at December 31, 2014 1,304 $ 18.71 5.70 $ 1 Outstanding at January 1, 2013 481 $ 12.69 0.96 $ 2 Granted 5,264 $ 19.32 Exercised (346 ) $ 10.82 $ 3 Expired (131 ) $ 19.31 Outstanding at December 31, 2013 5,268 $ 19.28 6.66 $ 41 Exercisable at December 31, 2013 1,552 $ 18.82 1.97 $ 13 ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option. As of December 31, 2015 , there was $8 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.56 years . The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During 2015, we did not recognize any reductions or excess in tax benefits related to stock options. During 2014 and 2013, we recognized excess tax benefits related to stock options of $3 million and $1 million , respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes. Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ 43 $ 46 $ 60 Oil and natural gas properties 23 29 52 Oil, natural gas and NGL production expenses 18 18 21 Marketing, gathering and compression expenses 5 6 7 Oilfield services expenses — 5 10 Total $ 89 $ 104 $ 150 Liability-Classified Awards Performance Share Units. In 2013, 2014 and 2015, we granted PSUs to senior management that vest ratably over a three -year term and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals such as finding and development costs and production and proved reserve growth. For PSUs granted in 2015, the TSR component can range from 0% to 100% , and each of the two operational components can range from 0% to 50% resulting in a maximum total payout of 200% . The payout percentage for these PSUs is capped at 100% if the Company’s absolute TSR is less than zero. For PSUs granted in 2014, the TSR component can range from 0% to 200% , with no operational components. For PSUs granted in 2013, the TSR component can range from 0% to 125% of base salary, and each of the two operational components can range from 0% to 62.5% ; however, the maximum total payout is capped at 200% . Compensation expense associated with PSU grants is recognized over the service period based on the graded-vesting method. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. The Company utilized the Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs: Volatility 55.76 % Risk-free interest rate 1.06 % Dividend yield for value of awards — % The following table presents a summary of our 2015, 2014 and 2013 PSU awards: Units Fair Value as of Grant Date Fair Value (a) Liability for Vested Amount (a) ($ in millions) 2015 Awards: Payable 2018 696,683 $ 13 2 1 2014 Awards: Payable 2017 609,637 $ 16 — — 2013 Awards: Payable 2016 1,701,941 $ 35 $ 4 $ 4 ___________________________________________ (a) As of December 31, 2015 . PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ (19 ) $ (4 ) $ 34 Restructuring and other termination costs (19 ) (19 ) 29 Marketing, gathering and compression (1 ) — 2 Oil and natural gas properties (2 ) 3 9 Oil, natural gas and NGL production expenses — — 2 Oilfield services expenses — — 1 Total $ (41 ) $ (20 ) $ 77 Effect of the Spin-off on Share-Based Compensation The employee matters agreement entered into in connection with the June 2014 spin-off of our oilfield services business (see Note 13) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs. Unvested equity-based compensation awards held by COO employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

Employee Benefit Plans (Note)

Employee Benefit Plans (Note)	12 Months Ended
	Dec. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Pension and Other Postretirement Benefits Disclosure	Employee Benefit Plans Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries except certain employees of Chesapeake Appalachia, L.L.C. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Through December 31, 2014, Chesapeake matched employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. Beginning January 1, 2015, Chesapeake matched employee contributions in cash. The Company contributed $52 million , $61 million and $81 million to the 401(k) Plan in 2015, 2014 and 2013, respectively. Chesapeake also maintains a nonqualified deferred compensation plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000 , have a hire date on or before December 1, immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Only the top 10% of Company wage earners are eligible to participate. Additionally, the employee had to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the DC Plan’s investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. The Company contributed $11 million , $7 million and $14 million to the DC Plan during 2015, 2014 and 2013, respectively, to fund the match. Beginning in 2016, the DC Plan will no longer be a spillover plan from the 401(k) Plan. The participant may choose separate deferral election percentages for both plans. The deferred compensation company match of 15% will continue in 2016 and will be based on a five -year vesting schedule based on years of service. Any participant who is active on December 31 of the plan year will receive the deferred compensation company match which will be awarded on an annual basis. Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plans are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plans. Chesapeake maintains no post-employment benefit plans except those sponsored by its wholly owned subsidiary Chesapeake Appalachia, L.L.C. Participation in these plans is limited to existing employees who are union members and former employees who were union members. The Chesapeake Appalachia, L.L.C. benefit plans provide health care and life insurance benefits to eligible employees upon retirement. We account for these benefits on an accrual basis. As of December 31, 2015, the Company had accrued approximately $3 million in accumulated post-employment benefit liability.

Derivative and Hedging Activiti

Derivative and Hedging Activities (Note)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative and Hedging Activities Disclosure	Derivative and Hedging Activities Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on its share of expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. All of our commodity derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. Oil and Natural Gas Derivatives As of December 31, 2015 and 2014, our oil and natural gas derivative instruments consisted of the following types of instruments: • Swaps : Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity. In exchange for higher fixed prices on certain of our swap trades, we granted options that allow the counterparty to double the notional amount. • Options : Chesapeake sells, and occasionally buys, call options in exchange for a premium. At the time of settlement, if the market price exceeds the fixed price of the call option, Chesapeake pays the counterparty the excess on sold call options and Chesapeake receives the excess on bought call options. If the market price settles below the fixed price of the call option, no payment is due from either party. • Basis Protection Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point. Chesapeake receives the fixed price differential and pays the floating market price differential to the counterparty for the hedged commodity. The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2015 and 2014 are provided below. December 31, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 13.5 $ 144 12.5 $ 471 Three-way collars — — 4.4 40 Call options 19.2 (7 ) 35.8 (89 ) Basis protection swaps — — — — Total oil 32.7 $ 137 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 500 $ 229 275 $ 281 Three-way collars — — 207 165 Call options 295 (99 ) 193 (170 ) Basis protection swaps 57 — 60 23 Total natural gas 852 $ 130 735 $ 299 Total estimated fair value $ 267 $ 721 We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) . Interest Rate Derivatives As of December 31, 2015 , there were no interest rate derivatives outstanding. As of December 31, 2014, our interest rate derivative instruments consisted of swaps. We enter into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our revolving credit facility borrowings. The notional amount of our interest rate derivatives associated with our long-term debt as of December 31, 2014 was $850 million . The estimated fair value of our interest rate derivative liabilities as of December 31, 2014 was $17 million . We have terminated certain fair value hedges related to certain of our senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years , we will recognize $7 million in net gains related to these transactions. Foreign Currency Derivatives We are party to cross currency swaps to mitigate our exposure to foreign currency exchange rate fluctuations. In December 2015, we exchanged in privately negotiated transactions and subsequently retired €42 million in aggregate principal amount of these senior notes, and we simultaneously unwound the cross currency swaps for the same principal amount at a cost of $8 million . As a result, we realized a loss of $8 million which was included in losses on purchases or exchanges of debt. Under the terms of the remaining cross currency swaps, on each semi-annual interest payment date, the counterparties pay us €9 million and we pay the counterparties $15 million , which yields an annual dollar-equivalent interest rate of 7.491% . Upon maturity of the notes, the counterparties will pay us €302 million and we will pay the counterparties $403 million . The terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. The swaps are designated as cash flow hedges and, because they are entirely effective in having eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates, changes in their fair value do not impact earnings. The fair values of the cross currency swaps are recorded on the consolidated balance sheets as liabilities of $52 million and $53 million as of December 31, 2015 and 2014, respectively. The euro-denominated debt in long-term debt has been adjusted to $329 million as of December 31, 2015 , using an exchange rate of $1.0862 to €1.00. Supply Contract Derivatives From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. In one of these supply contracts, we are committed to supply a minimum of 90 bbtu per day of natural gas through March 2025. In 2015, we recorded revenues of approximately $96 million for settlements of this embedded derivative. The bifurcated derivative was measured at fair value resulting in an unrealized gain of $297 million in 2015. Both settlements and mark-to-market gains (losses) are included in marketing, gathering and compression revenues in our consolidated statements of operations. Effect of Derivative Instruments – Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2015 and 2014 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Consolidated Balance Sheet Net Fair Value Presented in Consolidated Balance Sheet ($ in millions) As of December 31, 2015 Commodity Contracts: Short-term derivative asset $ 381 $ (66 ) $ 315 Long-term derivative asset — — — Short-term derivative liability (106 ) 66 (40 ) Long-term derivative liability (8 ) — (8 ) Total commodity contracts 267 — 267 Foreign Currency Contracts: (a) Long-term derivative liability (52 ) — (52 ) Total foreign currency contracts (52 ) — (52 ) Supply Contracts: Short-term derivative asset 51 — 51 Long-term derivative asset 246 — 246 Total supply contracts 297 — 297 Total derivatives $ 512 $ — $ 512 Balance Sheet Classification Gross Fair Value Amounts Netted in Consolidated Balance Sheet Net Fair Value Presented in Consolidated Balance Sheet As of December 31, 2014 Commodity Contracts: Short-term derivative asset $ 973 $ (95 ) $ 878 Long-term derivative asset 16 (10 ) 6 Short-term derivative liability (105 ) 95 (10 ) Long-term derivative liability (163 ) 10 (153 ) Total commodity contracts 721 — 721 Interest Rate Contracts: Short-term derivative liability (5 ) — (5 ) Long-term derivative liability (12 ) — (12 ) Total interest rate contracts (17 ) — (17 ) Foreign Currency Contracts: (a) Long-term derivative liability (53 ) — (53 ) Total foreign currency contracts (53 ) — (53 ) Supply Contracts: Short-term derivative asset 1 — 1 Long-term derivative asset — — — Total supply contracts 1 — 1 Total derivatives $ 652 $ — $ 652 ____________________________________________ (a) Designated as cash flow hedging instruments. As of December 31, 2015 and 2014, we did not have any cash collateral balances for these derivatives. Effect of Derivative Instruments – Consolidated Statements of Operations The components of oil, natural gas and NGL revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Oil, natural gas and NGL revenues $ 4,767 $ 9,336 $ 8,497 Gains (losses) on undesignated oil and natural gas derivatives 661 1,055 443 Losses on terminated cash flow hedges (37 ) (37 ) (314 ) Total oil, natural gas and NGL revenues $ 5,391 $ 10,354 $ 8,626 The components of marketing, gathering and compression revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Marketing, gathering and compression revenues $ 7,077 $ 12,224 $ 9,559 Gains on undesignated supply contract derivatives 296 1 — Total marketing, gathering and compression revenues $ 7,373 $ 12,225 $ 9,559 The components of interest expense for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Interest expense on senior notes $ 682 $ 704 $ 740 Interest expense on term loan — 36 116 Amortization of loan discount, issuance costs and other 59 42 91 Interest expense on credit facilities 12 28 38 Gains on terminated fair value hedges (3 ) (3 ) (5 ) (Gains) losses on undesignated interest rate derivatives (9 ) (81 ) 63 Capitalized interest (424 ) (637 ) (816 ) Total interest expense $ 317 $ 89 $ 227 Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below. Years Ended December 31, 2015 2014 2013 Before Tax After Tax Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (231 ) $ (143 ) $ (269 ) $ (167 ) $ (304 ) $ (189 ) Net change in fair value 32 20 1 1 3 2 Losses reclassified to income 39 24 37 23 32 20 Balance, end of period $ (160 ) $ (99 ) $ (231 ) $ (143 ) $ (269 ) $ (167 ) Approximately $113 million of the $99 million of accumulated other comprehensive loss as of December 31, 2015 represented the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. Deferred gain or loss amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of December 31, 2015 , we expect to transfer approximately $21 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022. Credit Risk Considerations Over-the-counter traded derivative instruments and our supply contracts expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of December 31, 2015 , our oil, natural gas, foreign currency and supply contract derivative instruments were spread among 16 counterparties. Hedging Arrangements As of December 31, 2015 , our secured commodity hedging facility with three counterparties provided approximately 94 mmboe of hedging capacity for oil, natural gas and NGL price derivatives and 94 mmboe for basis derivatives with an aggregate mark-to-market capacity of $1.5 billion . The facility, which was terminated in February 2016, was secured by proved reserves, the value of which covered the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. The counterparties’ obligations under the facility were required to be secured by cash or short-term U.S. treasury instruments to the extent that any mark-to-market amounts owed to us exceed defined thresholds. As of December 31, 2015 , we had hedged under the facility 1.2 mmboe of our future production with price derivatives. In 2015, we also began entering into bilateral hedging agreements with the intention of replacing and terminating the respective counterparties’ positions in the secured hedging facility. We also entered into bilateral arrangements that reduced the aggregate mark-to-market capacity under the secured hedging facility from $16.5 billion to $1.5 billion . The counterparties’ and our obligations under certain of the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. Our obligations under other bilateral hedging agreements are secured by the same collateral securing our revolving credit facility. As of December 31, 2015 , we had hedged under bilateral agreements 164.0 mmboe of our future production with price derivatives and 9.5 mmboe with basis derivatives. Fair Value The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Interest rate liabilities — — — — Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2015 and 2014 is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 100 316 Total purchases, issuances, sales and settlements: Settlements (137 ) (20 ) Ending balance as of December 31, 2015 $ (91 ) $ 297 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 292 1 Total purchases, issuances, sales and settlements: Settlements 136 — Transfers (b) (4 ) — Ending balance as of December 31, 2014 $ (54 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 100 $ 292 $ 296 $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ 43 $ 262 $ 296 $ — (b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values. Qualitative and Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements The significant unobservable inputs for Level 3 derivative contracts include unpublished forward prices of oil and natural gas, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts. For example, an increase or decrease in the forward prices and volatility of oil and natural gas prices decreases or increases the fair value of oil and natural gas derivatives, and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value December 31, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 26.87% – 43.08% 35.52% $ (7 ) Supply contracts (b) Oil price volatility curves 20.01% – 43.81% 24.07% $ 297 Natural gas trades (a) Natural gas price volatility curves 19.84% – 73.05% 34.29% $ (84 ) ___________________________________________ (a) Fair value is based on an estimate derived from option models. (b) Fair value is based on an estimate derived from industry standard methodologies which consider historical relationships among various commodities, modeled market prices, time value and volatility factors.

Oil and Natural Gas Property Tr

Oil and Natural Gas Property Transactions (Note)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Mergers, Acquisitions and Dispositions Disclosure	Oil and Natural Gas Property Transactions Under full cost accounting rules, we accounted for the sales of oil and natural gas properties discussed below as adjustments to capitalized costs, with no recognition of gain or loss as the sales did not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. 2015 Transactions CHK C-T sold all of its oil and natural gas properties to FourPoint and used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint for approximately $90 million . Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, in 2015 we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $66 million . 2014 Transactions We sold certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company for aggregate net proceeds of approximately $4.975 billion . We sold approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment. We exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI was the designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we were the designated operator. In conjunction with the exchange, we paid RKI approximately $450 million in cash. We sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE), for net proceeds of $233 million . We sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million . Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below. We sold noncore leasehold interests and producing properties in East Texas and Louisiana for net proceeds of approximately $63 million . All commitments related to VPP #6 will also transferred. See Volumetric Production Payments below. Excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, in 2014 we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $379 million . 2013 Transactions We sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus Corporation and Tug Hill Operating. Net proceeds from the transaction were approximately $490 million . MKR held producing wells and undeveloped acreage in the Marcellus Shale. We sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million . Subsequent to closing, we received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana. We sold noncore leasehold interests and producing properties in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million . Subsequent to closing, we received approximately $57 million and $32 million in 2014 and 2013, respectively, of additional net proceeds and for post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas. Joint Ventures Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies, including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Inc. (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion . In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of December 31, 2015 , we had utilized all drilling carries from our joint venture partners. In 2015, 2014 and 2013, our drilling and completion costs included the benefit of approximately $51 million , $679 million and $884 million , respectively, in drilling and completion carries paid by our joint venture partners. In 2013, we entered into a joint venture with Sinopec in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippian Lime play in northern Oklahoma for $1.11 billion . There was no drilling and completion carry associated with this transaction. In 2015, 2014 and 2013, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $33 million , $33 million and $58 million , respectively. Volumetric Production Payments From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we novated to each of the respective VPP buyers hedges that covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores. As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our consolidated statements of operations in the periods these costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining our full cost ceiling test for impairment purposes and in determining our standardized measure. Pursuant to SEC guidelines, the estimates used for purposes of determining the cost center ceiling and the standardized measure are based on current costs. Our commitment to bear the costs on any future production of VPP volumes is not reflected as a liability on our balance sheet. The costs that will apply in the future will depend on the actual production volumes as well as the production costs and taxes in effect during the periods in which the production actually occurs, which could differ materially from our current and historical costs, and production may not occur at the times or in the quantities projected, or at all. For accounting purposes, cash proceeds from the sale of VPPs were reflected as a reduction of oil and natural gas properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. As of December 31, 2015 , our outstanding VPPs consisted of the following: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 10 March 2012 Anadarko Basin Granite Wash $ 744 3.0 87 9.2 160 9 May 2011 Mid-Continent 853 1.7 138 4.8 177 4 December 2008 Anadarko and Arkoma Basins 412 0.5 95 — 98 3 August 2008 Anadarko Basin 600 — 93 — 93 2 May 2008 Texas, Oklahoma and Kansas 622 — 94 — 94 1 December 2007 Kentucky and West Virginia 1,100 — 208 — 208 $ 4,331 5.2 715 14.0 830 The volumes produced on behalf of our VPP buyers during 2015, 2014 and 2013 were as follows: Year Ended December 31, 2015 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 310.0 8.5 1,043.9 16.6 9 167.9 14.2 375.9 17.4 8 (a) — 36.5 — 36.5 4 42.5 8.0 — 8.2 3 — 6.4 — 6.4 2 — 4.0 — 4.0 1 — 13.3 — 13.3 520.4 90.9 1,419.8 102.4 Year Ended December 31, 2014 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 403.0 10.6 1,296.5 20.7 9 187.5 15.4 411.0 19.0 8 — 60.1 — 60.1 6 (b) 23.1 4.2 — 4.3 5 (b) 16.5 4.6 — 4.7 4 48.1 9.0 — 9.2 3 — 7.2 — 7.2 2 — 6.2 — 6.2 1 — 13.8 — 13.8 678.2 131.1 1,707.5 145.2 Year Ended December 31, 2013 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 547.0 13.5 1,509.0 25.8 9 213.2 17.0 455.7 21.0 8 — 68.1 — 68.1 6 24.0 4.8 — 4.9 5 25.4 7.5 — 7.7 4 54.7 10.2 — 10.5 3 — 8.1 — 8.1 2 — 10.3 — 10.3 1 — 14.5 — 14.5 864.3 154.0 1,964.7 170.9 ____________________________________________ (a) VPP #8 expired in 2015. (b) We divested the properties associated with VPP #5 and VPP #6 in 2014. The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2015 were as follows: Volume Remaining as of December 31, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 74 1.0 29.6 3.6 57.4 9 62 0.7 59.0 1.6 72.4 4 12 — 7.3 — 7.6 3 43 — 17.5 — 17.5 2 40 — 9.8 — 9.8 1 84 — 78.3 — 78.3 1.7 201.5 5.2 243.0

Spin-Off of Oilfield Services B

Spin-Off of Oilfield Services Business (Note)	12 Months Ended
	Dec. 31, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure	Spin-Off of Oilfield Services Business On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into SSE, an independent, publicly traded company. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution. Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions: • COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s then-existing credit facility. • COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 16 for further discussion of the sale. • We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off. • COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes. • COO converted from a limited liability company into SSE, a publicly-traded corporation. • We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company. Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements we entered into in connection with the spin-off, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “Former Oilfield Services”. See Note 21 for additional information regarding our segments. In connection with the spin-off, we entered into several agreements to define the terms and conditions of the spin-off and our ongoing relationship with SSE after the spin-off, including a master separation agreement, a tax sharing agreement, an employee matters agreement, a transition services agreement, a services agreement and certain commercial agreements. These agreements, among other things, allocate responsibility for obligations arising before and after the distribution date, including obligations relating to taxes, employees, various transition services and oilfield services. • The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off. • The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes. • The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 9 for additional information regarding the effect of the spin-off on outstanding equity compensation. • The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services. This agreement was terminated in 2015. • The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 4 for a summary of the terms of the services agreement. • We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of December 31, 2015, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $227 million . In 2014, our stockholders’ equity decreased by $270 million , net of $151 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations.

Investments (Note)

Investments (Note)	12 Months Ended
	Dec. 31, 2015
Investments [Abstract]
Investments Disclosure	Investments A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2015 and 2014, is presented below. Approximate Ownership % Carrying Value Accounting Method December 31, December 31, December 31, December 31, ($ in millions) Sundrop Fuels, Inc. Equity 56% 56% $ 119 $ 130 FTS International, Inc. Equity 30% 30% — 116 Other — —% —% 17 19 Total investments $ 136 $ 265 Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. In 2015, we recorded a $20 million charge related to our share of Sundrop's net loss and $9 million of capitalized interest associated with the construction of Sundrop’s plant. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $87 million as of December 31, 2015 and will be amortized over the life of the plant once it is placed into service. FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. In 2015, we recorded our equity in FTS’ net losses and other adjustments, prior to intercompany profit eliminations, of $107 million and an accretion adjustment of $44 million related to the excess of our underlying equity in net assets of FTS over our carrying value. Due to the decrease in the oil and natural gas pricing environment, we recognized an other-than-temporary impairment on our investment in FTS of $53 million during the 2015 fourth quarter. Sold Investments Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In 2014, we sold all of our interest in Chaparral for net cash proceeds of $209 million . We recorded a $73 million gain related to the sale. Clean Energy Fuels Corp . In 2013, we sold all of our shares of Clean Energy Fuels Corp. (Clean Energy) common stock for cash proceeds of approximately $13 million . We recorded a $3 million gain related to the sale. In 2013, we sold our $100 million investment in convertible notes of Clean Energy for cash proceeds of $85 million . The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale. Gastar Exploration Ltd . In 2013, we sold our investment in Gastar Exploration Ltd. for cash proceeds of $10 million . Other. In 2014, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction. In 2013, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

Variable Interest Entities (Not

Variable Interest Entities (Note)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Variable Interest Entities Disclosure	Variable Interest Entities We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. Consolidated VIE Chesapeake Granite Wash Trust . For a discussion of the formation, operations and presentation of the Trust, see Noncontrolling Interests in Note 8. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest. The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of December 31, 2015 , $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $428 million of accumulated depreciation, depletion and amortization and $8 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake. Unconsolidated VIE Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million , and the partnership will acquire the remaining 90% up to a maximum of $225 million , funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5% . The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment. The carrying value of our investment was $10 million as of December 31, 2015 .

Other Property and Equipment (N

Other Property and Equipment (Note)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Other Property and Equipment Disclosure	Other Property and Equipment Other Property and Equipment A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: December 31, Estimated Useful Life 2015 2014 ($ in millions) (in years) Buildings and improvements $ 1,209 $ 1,242 10 – 39 Natural gas compressors (a) 483 551 3 – 20 Land 289 296 Gathering systems and treating plants (a) 214 218 20 Other 732 776 2 – 20 Total other property and equipment, at cost 2,927 3,083 Less: accumulated depreciation $ (813 ) $ (804 ) Total other property and equipment, net $ 2,114 $ 2,279 ___________________________________________ (a) Included in our marketing, gathering and compression operating segment. Net (Gains) Losses on Sales of Fixed Assets A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Buildings and land $ 3 $ (2 ) $ 27 Natural gas compressors — (195 ) — Gathering systems and treating plants 1 8 (326 ) Oilfield services equipment — (7 ) 2 Other — (3 ) (5 ) Total net (gains) losses on sales of fixed assets $ 4 $ (199 ) $ (302 ) Buildings and Land. The net losses in 2015, net gains in 2014 and the net losses in 2013 on sales of buildings and land were mainly from the sale of certain buildings and land located primarily in Oklahoma City and our Barnett Shale operating area. Natural Gas Compressors . In 2014, we sold 703 compressors to various parties for $693 million and recorded an aggregate gain of $195 million on the sales. Gathering Systems and Treating Plants. In 2013, we sold our wholly owned midstream subsidiary Mid-America Midstream Gas Services, L.L.C. to SemGas, L.P., a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million . We recorded a $141 million gain associated with the transaction. In 2013, we also sold our wholly owned subsidiary Granite Wash Midstream Gas Services, L.L.C. to MarkWest Oklahoma Gas Company, L.L.C. (MW), a wholly owned subsidiary of MarkWest Energy Partners, L.P., for net proceeds of approximately $252 million . We recorded a $105 million gain associated with this transaction. The transaction with MW included long-term fixed fee arrangements for gas gathering, compression, treating and processing services in the Anadarko Basin. In 2013, we also sold our interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP for proceeds of approximately $134 million . We recorded a $55 million gain associated with this transaction. Oilfield Services Equipment. In 2014, we sold substantially all of our crude oil hauling assets for approximately $44 million . We recorded a $23 million gain associated with the transaction. Also, in 2014, we sold 14 rigs for approximately $14 million and recorded a $14 million loss. Assets Held for Sale We are continuing to pursue the sale of buildings and land located primarily in Oklahoma, West Virginia and the Fort Worth, Texas area. Buildings and land are recorded within our other segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of December 31, 2015 . Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. As of December 31, 2015 and 2014, we had $95 million and $93 million , respectively, of buildings and land, net of accumulated depreciation, classified as assets held for sale on our consolidated balance sheets.

Impairments (Note)

Impairments (Note)	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Asset Impairment Charges Disclosure	Impairments Impairments of Oil and Natural Gas Properties On a quarterly basis, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter and leasehold that is no longer part of our development strategy and will be abandoned. As commodity prices have decreased significantly over the past 12 months, we transferred, in 2015, noncore unproved leasehold in all of our operating areas having a cost of approximately $1.9 billion that would not be a part of our development strategy going forward. Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. Estimated future net revenues for the quarterly ceiling limit are calculated using the average of commodity prices on the first day of the month over the trailing 12-month period. During 2015, capitalized costs of oil and natural gas properties exceeded the ceiling, resulting in an impairment in the carrying value of our oil and natural gas properties of $18.238 billion . During 2015, cash flow hedges which related to future periods, increased the ceiling test impairment by $176 million . Based on the first-day-of-the-month prices we have received over the 11 months ended February 1, 2016, we expect to record another material write-down in the carrying value of our oil and natural gas properties in the first quarter of 2016. Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters. Impairments of Fixed Assets and Other We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Natural gas compressors $ 21 $ 11 $ — Buildings and land — 18 366 Gathering systems and treating plants — 13 22 Oilfield services equipment — 23 71 Other 173 23 87 Total impairments of fixed assets and other $ 194 $ 88 $ 546 Natural Gas Compressors. In 2015, we recorded a $21 million impairment related to 465 compressors for the difference between the aggregate sales price of $40 million and the carrying value. Buildings and Land. In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. We recognized an impairment loss of $186 million on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. Given the impairment losses associated with these assets, we tested other noncore buildings and land that we owned in the Oklahoma City area for recoverability. As a result of this test, we recognized an impairment loss of $69 million on these assets in 2013. Due to a decrease in the estimated market prices of certain property classified as held for sale in the Fort Worth area, we recognized an additional impairment loss of $86 million in 2013. We tested other noncore surface land that we owned in the Fort Worth area for recoverability in 2013 and recognized an additional impairment loss of $10 million on these assets for the difference between the carrying amount and fair value of the assets. Finally, we recorded an impairment loss of approximately $15 million on certain of our buildings and land outside of the Oklahoma City and Fort Worth areas in 2013. All the buildings and land for which impairment losses were recognized in 2015, 2014 and 2013 are included in our other segment. Oilfield Services Equipment. In 2014, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million . In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. The drilling rigs and equipment are included in our former oilfield services operating segment. In 2013, we purchased 23 leased rigs from various lessors for an aggregate purchase price of $141 million and paid approximately $22 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we impaired approximately $22 million related to leasehold improvements and other costs associated with these assets. In 2013, we also recognized $27 million of impairment losses on certain of our drilling rigs for the difference between the carrying amount and fair value, less the anticipated costs to sell. We estimated the fair value using prices expected to be received. Other. In 2015, we recorded a $47 million loss contingency related to contract disputes. In 2015, we recorded a $22 million impairment of a note receivable as a result of the increased credit risk associated with declining commodity prices. In addition, under the terms of our joint venture agreements (see Note 12), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In 2015, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge. In 2015, as a result of reductions in our planned drilling activity in response to declines in oil and natural gas prices, we terminated contracts with drilling contractors and incurred charges of $18 million . Further contract termination charges in subsequent quarters may occur if commodity prices remain low or continue to decline. The contract termination charges are included in our exploration and production operating segment. In 2014, we revised our estimate of our net acreage shortfall with Total under the terms of our Barnett Shale joint venture agreement and recorded a $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. In 2013, we recorded a $26 million charge for terminating a gas gathering agreement, a $28 million charge for the impairment of certain assets used to promote natural gas demand and $15 million for the termination of a contract drilling agreement with a third party. Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.

Restructuring and Other Termina

Restructuring and Other Termination Costs (Note)	12 Months Ended
	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure	Restructuring and Other Termination Costs A summary of our restructuring and other termination costs for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Restructuring charges under workforce reduction plan: Salary expense $ 47 $ — $ 20 Acceleration of stock-based compensation — — 45 Other termination benefits 8 — 1 Total restructuring changes under workforce reduction plan 55 — 66 Oilfield services spin-off costs: Transaction costs — 17 — Stock-based compensation adjustments for Chesapeake employees — 5 — Stock-based compensation forfeitures for SSE employees — (10 ) — Debt extinguishment costs — 3 — Total oilfield services spin-off costs — 15 — Termination benefits provided to Mr. McClendon: Salary and bonus expense — — 11 Acceleration of 2008 performance bonus clawback — — 11 Acceleration of stock-based compensation — — 22 Acceleration of performance share unit awards (a) (8 ) (8 ) 18 Estimated aircraft usage benefits — — 7 Total termination benefits provided to Mr. McClendon (8 ) (8 ) 69 Termination benefits provided to VSP participants: Salary and bonus expense — — 33 Acceleration of stock-based compensation — — 29 Other termination benefits — — 1 Total termination benefits provided to VSP participants — — 63 Other termination benefits (a) (11 ) — 50 Total restructuring and other termination costs $ 36 $ 7 $ 248 ____________________________________________ (a) Amounts for the years ended December 31, 2015 and 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9. Workforce Reductions On September 29, 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million in 2015 for one-time termination benefits. On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we incurred a charge of approximately $66 million . Oilfield Services Spin-Off On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, in 2014, we incurred restructuring charges of $15 million consisting of transaction costs, stock-based compensation adjustments and debt extinguishment costs. See Note 13 for further discussion of the spin-off. Other On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In 2013, we incurred charges of approximately $69 million related to Mr. McClendon’s departure. In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period, which resulted in $63 million of expense for 2013. During 2013, we also incurred charges of approximately $50 million related to other workforce reductions, including separations of executive officers other than the former CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment. We recognized a credit of $19 million in 2015 related to negative fair value adjustments to PSUs granted to former executives of the Company which corresponded to a decrease in the trading price of our common stock

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Note)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements Disclosure	Fair Value Measurements Recurring Fair Value Measurements Other Current Assets. Assets related to Chesapeake’s deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities. Other Current Liabilities . Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds. Financial Assets (Liabilities) . The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 ) See Note 3 for information regarding fair value measurement of our debt instruments. See Note 11 for information regarding fair value measurement of our derivatives. Nonrecurring Fair Value Measurements See Note 17 regarding nonrecurring fair value measurements.

Asset Retirement Obligations (N

Asset Retirement Obligations (Note)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure	Asset Retirement Obligations The components of the change in our asset retirement obligations are shown below. Years Ended December 31, 2015 2014 ($ in millions) Asset retirement obligations, beginning of period $ 465 $ 405 Additions 6 29 Revisions (a) 13 101 Settlements and disposals (34 ) (92 ) Accretion expense 23 22 Asset retirement obligations, end of period 473 465 Less current portion (b) 21 18 Asset retirement obligation, long-term $ 452 $ 447 _________________________________________ (a) Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement. (b) Balance is included in other current liabilities on the consolidated balance sheet.

Major Customers and Segment Inf

Major Customers and Segment Information (Note)	12 Months Ended
	Dec. 31, 2015
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Segment Information Disclosure	Major Customers and Segment Information Sales to BP PLC constituted approximately 14% of our total revenues (before the effects of hedging) for the year ended December 31, 2015. Sales to Exxon Mobil Corporation constituted approximately 12% of our total revenues (before the effects of hedging) for the year ended December 31, 2014. There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the year ended December 31, 2013. As of December 31, 2015 , we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off of our oilfield services business in June 2014, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below. Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $4.372 billion , $8.565 billion and $7.570 billion for the years ended December 31, 2015, 2014 and 2013, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million and $1.309 billion for the years ended December 31, 2014 and 2013, respectively. No income was recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2015 Revenues $ 5,391 $ 11,745 $ — $ — $ (4,372 ) $ 12,764 Intersegment revenues — (4,372 ) — — 4,372 — Total revenues $ 5,391 $ 7,373 $ — $ — $ — $ 12,764 Unrealized losses on commodity derivatives $ 693 $ — $ — $ — $ — $ 693 Unrealized gains on marketing derivatives $ — $ (295 ) $ — $ — $ — $ (295 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,170 $ 20 $ — $ 39 $ — $ 2,229 Impairment of oil and natural gas properties $ 18,238 $ — $ — $ — $ — $ 18,238 Impairments of fixed assets and other $ 126 $ 68 $ — $ — $ — $ 194 Net gain (loss) on sales of fixed assets $ 1 $ 1 $ — $ 2 $ — $ 4 Interest expense $ (925 ) $ (4 ) $ — $ 6 $ 606 $ (317 ) Losses on investments $ (3 ) $ — $ — $ (93 ) $ — $ (96 ) Impairments of investments $ — $ — $ — $ (53 ) $ — $ (53 ) Gains on purchases or exchanges of debt $ 279 $ — $ — $ — $ — $ 279 Income (Loss) Before Income Taxes $ (19,619 ) $ 117 $ — $ (127 ) $ 531 $ (19,098 ) Total Assets $ 11,819 $ 1,524 $ — $ 4,325 $ (311 ) $ 17,357 Capital Expenditures $ 3,562 $ 42 $ — $ 10 $ — $ 3,614 Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2014 Revenues $ 10,354 $ 20,790 $ 1,060 $ 30 $ (9,109 ) $ 23,125 Intersegment revenues — (8,565 ) (544 ) — 9,109 — Total revenues $ 10,354 $ 12,225 $ 516 $ 30 $ — $ 23,125 Unrealized gains on commodity derivatives $ (1,394 ) $ — $ — $ — $ — $ (1,394 ) Unrealized gains on marketing derivatives $ — $ (3 ) $ — $ — $ — $ (3 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,756 $ 38 $ 145 $ 42 $ (66 ) $ 2,915 Impairments of fixed assets and other $ 22 $ 24 $ 23 $ 19 $ — $ 88 Net gain (loss) on sales of fixed assets $ (2 ) $ (187 ) $ (8 ) $ (2 ) $ — $ (199 ) Interest expense $ (709 ) $ (21 ) $ (42 ) $ 3 $ 680 $ (89 ) Losses on investments $ 2 $ — $ (1 ) $ (76 ) $ — $ (75 ) Impairments of investments $ — $ — $ (5 ) $ — $ — $ (5 ) Net gain (loss) on sales of investments $ (6 ) $ — $ — $ 73 $ — $ 67 Losses on purchases or exchanges of debt $ (197 ) $ — $ — $ — $ — $ (197 ) Income (Loss) Before Income Taxes $ 2,874 $ 326 $ (16 ) $ (30 ) $ 46 $ 3,200 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751 Capital Expenditures $ 6,173 $ 298 $ 158 $ 38 $ — $ 6,667 Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2013 Revenues $ 8,626 $ 17,129 $ 2,188 $ 29 $ (8,892 ) $ 19,080 Intersegment revenues — (7,570 ) (1,309 ) (13 ) 8,892 — Total revenues $ 8,626 $ 9,559 $ 879 $ 16 $ — $ 19,080 Unrealized gains on commodity derivatives $ (228 ) $ — $ — $ — $ — $ (228 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,674 $ 46 $ 289 $ 49 $ (155 ) $ 2,903 Impairments of fixed assets and other $ 27 $ 50 $ 75 $ 394 $ — $ 546 Net gain (loss) on sales of fixed assets $ 2 $ (329 ) $ (1 ) $ 26 $ — $ (302 ) Interest expense $ (918 ) $ (24 ) $ (82 ) $ (74 ) $ 871 $ (227 ) Losses on investments $ 3 $ — $ — $ (219 ) $ — $ (216 ) Impairments of investments $ — $ — $ (1 ) $ (10 ) $ 1 $ (10 ) Net gain (loss) on sales of investments $ — $ — $ — $ (7 ) $ — $ (7 ) Losses on purchases or exchanges of debt $ (193 ) $ — $ — $ — $ — $ (193 ) Income (Loss) Before Income Taxes $ 2,997 $ 511 $ (51 ) $ (727 ) $ (1,288 ) $ 1,442 Total Assets $ 35,341 $ 2,430 $ 2,018 $ 5,750 $ (3,757 ) $ 41,782 Capital Expenditures $ 6,198 $ 299 $ 272 $ 421 $ — $ 7,190

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Note)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent Company Only Disclosure	Condensed Consolidating Financial Information Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. Our former oilfield services subsidiaries were separately capitalized and were not guarantors of our debt obligations. The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2015 and 2014 and for the years ended December 31, 2015 , 2014 and 2013. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 928 $ 2 $ 1 $ (106 ) $ 825 Other current assets 87 1,561 7 — 1,655 Intercompany receivable, net 24,789 — 434 (25,223 ) — Total Current Assets 25,804 1,563 442 (25,329 ) 2,480 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 11,861 69 159 12,089 Other property and equipment, net — 2,113 1 — 2,114 Property and equipment held for sale, net — 95 — — 95 Total Property and Equipment, Net — 14,069 70 159 14,298 LONG-TERM ASSETS: Other long-term assets 74 495 10 — 579 Investments in subsidiaries and intercompany advances (12,349 ) 771 — 11,578 — TOTAL ASSETS $ 13,529 $ 16,898 $ 522 $ (13,592 ) $ 17,357 CURRENT LIABILITIES: Current liabilities $ 921 $ 2,862 $ 8 $ (106 ) $ 3,685 Intercompany payable, net — 25,580 — (25,580 ) — Total Current Liabilities 921 28,442 8 (25,686 ) 3,685 LONG-TERM LIABILITIES: Long-term debt, net 10,354 — — — 10,354 Other long-term liabilities 116 805 — — 921 Total Long-Term Liabilities 10,470 805 — — 11,275 EQUITY: Chesapeake stockholders’ equity 2,138 (12,349 ) 514 11,835 2,138 Noncontrolling interests — — — 259 259 Total Equity 2,138 (12,349 ) 514 12,094 2,397 TOTAL LIABILITIES AND EQUITY $ 13,529 $ 16,898 $ 522 $ (13,592 ) $ 17,357 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 Restricted cash — — 38 — 38 Other current assets 55 3,174 93 — 3,322 Intercompany receivable, net 24,527 — 341 (24,868 ) — Total Current Assets 28,682 3,176 556 (24,946 ) 7,468 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 28,358 1,112 673 30,143 Other property and equipment, net — 2,276 3 — 2,279 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 30,727 1,115 673 32,515 LONG-TERM ASSETS: Other long-term assets 153 618 26 (29 ) 768 Investments in subsidiaries and intercompany advances 126 467 — (593 ) — TOTAL ASSETS $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CURRENT LIABILITIES: Current liabilities $ 761 $ 4,915 $ 58 $ (78 ) $ 5,656 Intercompany payable, net — 24,940 — (24,940 ) — Total Current Liabilities 761 29,855 58 (25,018 ) 5,656 LONG-TERM LIABILITIES: Long-term debt, net 11,154 — — — 11,154 Deferred income tax liabilities 31 3,917 244 200 4,392 Other long-term liabilities 112 1,090 142 — 1,344 Total Long-Term Liabilities 11,297 5,007 386 200 16,890 EQUITY: Chesapeake stockholders’ equity 16,903 126 1,253 (1,379 ) 16,903 Noncontrolling interests — — — 1,302 1,302 Total Equity 16,903 126 1,253 (77 ) 18,205 TOTAL LIABILITIES AND EQUITY $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 5,252 $ 139 $ — $ 5,391 Marketing, gathering and compression — 7,373 — — 7,373 Total Revenues — 12,625 139 — 12,764 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,019 27 — 1,046 Oil, natural gas and NGL gathering, processing and transportation — 2,094 25 — 2,119 Production taxes — 97 2 — 99 Marketing, gathering and compression — 7,129 1 — 7,130 General and administrative 1 231 3 — 235 Restructuring and other termination costs — 36 — — 36 Provision for legal contingencies 339 14 — — 353 Oil, natural gas and NGL depreciation, depletion and amortization — 2,051 69 (21 ) 2,099 Depreciation and amortization of other assets — 130 — — 130 Impairment of oil and natural gas properties — 18,224 472 (458 ) 18,238 Impairments of fixed assets and other — 194 — — 194 Net gains on sales of fixed assets — 4 — — 4 Total Operating Expenses 340 31,223 599 (479 ) 31,683 LOSS FROM OPERATIONS (340 ) (18,598 ) (460 ) 479 (18,919 ) OTHER INCOME (EXPENSE): Interest expense (721 ) (198 ) — 602 (317 ) Losses on investments — (96 ) — — (96 ) Impairments of investments — (53 ) — — (53 ) Gains on purchases or exchanges of debt 279 — — — 279 Other income (expense) 140 10 1 (143 ) 8 Equity in net earnings (losses) of subsidiary (14,197 ) (402 ) — 14,599 — Total Other Expense (14,499 ) (739 ) 1 15,058 (179 ) LOSS BEFORE INCOME TAXES (14,839 ) (19,337 ) (459 ) 15,537 (19,098 ) INCOME TAX EXPENSE (BENEFIT) (154 ) (4,421 ) (107 ) 219 (4,463 ) NET LOSS (14,685 ) (14,916 ) (352 ) 15,318 (14,635 ) Net income attributable to noncontrolling interests — — — (50 ) (50 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (14,685 ) (14,916 ) (352 ) 15,268 (14,685 ) Other comprehensive income 21 23 — — 44 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (14,664 ) $ (14,893 ) $ (352 ) $ 15,268 $ (14,641 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 9,899 $ 458 $ (3 ) $ 10,354 Marketing, gathering and compression — 12,220 5 — 12,225 Oilfield services — 41 983 (478 ) 546 Total Revenues — 22,160 1,446 (481 ) 23,125 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,166 42 — 1,208 Oil, natural gas and NGL gathering, processing and transportation — 2,134 40 — 2,174 Production taxes — 227 5 — 232 Marketing, gathering and compression — 12,232 4 — 12,236 Oilfield services — 53 769 (391 ) 431 General and administrative — 273 49 — 322 Restructuring and other termination costs — 4 3 — 7 Provision for legal contingencies 100 134 — — 234 Oil, natural gas and NGL depreciation, depletion and amortization — 2,523 162 (2 ) 2,683 Depreciation and amortization of other assets — 153 143 (64 ) 232 Impairment of oil and natural gas — — 349 (349 ) — Impairments of fixed assets and other — 65 23 — 88 Net gains on sales of fixed assets — (192 ) (7 ) — (199 ) Total Operating Expenses 100 18,772 1,582 (806 ) 19,648 INCOME (LOSS) FROM OPERATIONS (100 ) 3,388 (136 ) 325 3,477 OTHER INCOME (EXPENSE): Interest expense (657 ) (37 ) (42 ) 647 (89 ) Losses on investments — (77 ) — 2 (75 ) Impairments of investments — — (5 ) — (5 ) Net gain of sales of investments — 67 — — 67 Losses on purchases or exchanges of debt (195 ) (2 ) — — (197 ) Other income (expense) 502 198 (2 ) (676 ) 22 Equity in net earnings (losses) of subsidiary 2,206 (258 ) — (1,948 ) — Total Other Income (Expense) 1,856 (109 ) (49 ) (1,975 ) (277 ) INCOME (LOSS) BEFORE INCOME TAXES 1,756 3,279 (185 ) (1,650 ) 3,200 INCOME TAX EXPENSE (BENEFIT) (161 ) 1,264 (66 ) 107 1,144 NET INCOME (LOSS) 1,917 2,015 (119 ) (1,757 ) 2,056 Net income attributable to noncontrolling interests — — — (139 ) (139 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 1,917 2,015 (119 ) (1,896 ) 1,917 Other comprehensive income 1 18 — — 19 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $ 1,918 $ 2,033 $ (119 ) $ (1,896 ) $ 1,936 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2013 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 8,013 $ 553 $ 60 $ 8,626 Marketing, gathering and compression — 9,547 12 — 9,559 Oilfield services — 221 1,836 (1,162 ) 895 Total Revenues — 17,781 2,401 (1,102 ) 19,080 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,112 47 — 1,159 Oil, natural gas and NGL gathering, processing and transportation — 1,574 — — 1,574 Production taxes — 222 7 — 229 Marketing, gathering and compression — 9,455 6 — 9,461 Oilfield services — 239 1,434 (937 ) 736 General and administrative — 375 83 (1 ) 457 Restructuring and other termination costs — 244 4 — 248 Oil, natural gas and NGL depreciation, depletion and amortization — 2,336 253 — 2,589 Depreciation and amortization of other assets — 180 281 (147 ) 314 Impairment of oil and natural gas — (2 ) 313 (311 ) — Impairments of fixed assets and other — 417 129 — 546 Net gains on sales of fixed assets — (301 ) (1 ) — (302 ) Total Operating Expenses — 15,851 2,556 (1,396 ) 17,011 INCOME (LOSS) FROM OPERATIONS — 1,930 (155 ) 294 2,069 OTHER INCOME (EXPENSE): Interest expense (921 ) (4 ) (85 ) 783 (227 ) Losses on investments — (216 ) — — (216 ) Impairments of investments — (9 ) (1 ) — (10 ) Net loss on sales of investments — (7 ) — — (7 ) Losses on purchases or exchanges of debt (70 ) (123 ) — — (193 ) Other income (expense) 3,979 (603 ) 13 (3,363 ) 26 Equity in net earnings (losses) of subsidiary (1,129 ) (383 ) — 1,512 — Total Other Income (Expense) 1,859 (1,345 ) (73 ) (1,068 ) (627 ) INCOME (LOSS) BEFORE INCOME TAXES 1,859 585 (228 ) (774 ) 1,442 INCOME TAX EXPENSE (BENEFIT) 1,135 369 (87 ) (869 ) 548 NET INCOME (LOSS) 724 216 (141 ) 95 894 Net income attributable to noncontrolling interests — — — (170 ) (170 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 724 216 (141 ) (75 ) 724 Other comprehensive income (loss) 3 19 (2 ) — 20 COMPREHENSIVE INCOME (LOSS) $ 727 $ 235 $ (143 ) $ (75 ) $ 744 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 1,142 $ 110 $ (18 ) $ 1,234 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (3,032 ) (63 ) — (3,095 ) Acquisitions of proved and unproved properties — (529 ) (4 ) — (533 ) Proceeds from divestitures of proved and unproved properties — 152 37 — 189 Additions to other property and equipment — (148 ) 5 — (143 ) Other investing activities — 67 52 12 131 Net Cash Used In Investing Activities — (3,490 ) 27 12 (3,451 ) CASH FLOWS FROM FINANCING ACTIVITIES: Cash paid to repurchase noncontrolling interest of CHK C-T — — (143 ) — (143 ) Cash paid to purchase debt (508 ) — — — (508 ) Other financing activities (789 ) 473 (77 ) (22 ) (415 ) Intercompany advances, net (1,875 ) 1,875 — — — Net Cash Provided by (Used In) Financing Activities (3,172 ) 2,348 (220 ) (22 ) (1,066 ) Net decrease in cash and cash equivalents (3,172 ) — (83 ) (28 ) (3,283 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 928 $ 2 $ 1 $ (106 ) $ 825 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 4,201 $ 462 $ (29 ) $ 4,634 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (4,445 ) (136 ) — (4,581 ) Acquisitions of proved and unproved properties — (1,306 ) (5 ) — (1,311 ) Proceeds from divestitures of proved and unproved properties — 5,812 1 — 5,813 Additions to other property and equipment — (480 ) (246 ) — (726 ) Other investing activities — 1,199 60 — 1,259 Net Cash Provided By (Used In) Investing Activities — 780 (326 ) — 454 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 6,689 717 — 7,406 Payments on credit facilities borrowings — (6,689 ) (1,099 ) — (7,788 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,966 — 494 — 3,460 Proceeds from issuance of oilfield services term loan, net of issuance costs — — 394 — 394 Cash paid to purchase debt (3,362 ) — — — (3,362 ) Other financing activities (439 ) (1,278 ) (169 ) (41 ) (1,927 ) Intercompany advances, net 4,136 (3,709 ) (427 ) — — Net Cash Provided By (Used In) Financing Activities 3,301 (4,987 ) (90 ) (41 ) (1,817 ) Net increase (decrease) in cash and cash equivalents 3,301 (6 ) 46 (70 ) 3,271 Cash and cash equivalents, beginning of period 799 8 38 (8 ) 837 Cash and cash equivalents, end of period $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2013 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 4,218 $ 439 $ (43 ) $ 4,614 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (4,838 ) (766 ) — (5,604 ) Acquisitions of proved and unproved properties — (1,378 ) 346 — (1,032 ) Proceeds from divestitures of proved and unproved properties — 3,466 1 — 3,467 Additions to other property and equipment — (271 ) (701 ) — (972 ) Other investing activities — 246 765 163 1,174 Net Cash Used In Investing Activities — (2,775 ) (355 ) 163 (2,967 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 6,452 1,217 — 7,669 Payments on credit facilities borrowings — (6,452 ) (1,230 ) — (7,682 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,274 — — — 2,274 Cash paid to purchase debt (2,141 ) — — — (2,141 ) Proceeds from sales of noncontrolling interests — — 6 — 6 Other financing activities 1,819 (2,897 ) (17 ) (128 ) (1,223 ) Intercompany advances, net (1,381 ) 1,462 (81 ) — — Net Cash Provided By (Used In) Financing Activities 571 (1,435 ) (105 ) (128 ) (1,097 ) Net increase (decrease) in cash and cash equivalents 571 8 (21 ) (8 ) 550 Cash and cash equivalents, beginning of period 228 — 59 — 287 Cash and cash equivalents, end of period $ 799 $ 8 $ 38 $ (8 ) $ 837

Recently Issued Accounting Stan

Recently Issued Accounting Standards (Note)	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles Disclosure	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. We are evaluating the impact of this guidance on our consolidated financial statements. In April 2015, the FASB issued an accounting standards update on the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements. In August 2015, the FASB issued an accounting standards update which allows for debt issuance costs related to line-of-credit arrangements to be presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements.

Subsequent Events (Subsequent E

Subsequent Events (Subsequent Events (Note)	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events Subsequent to December 31, 2015, we repurchased in the open market approximately $60 million of our outstanding 2.5% Contingent Convertible Notes due 2037 for $32 million , $122 million of our 3.25% Senior Notes due 2016 for $115 million and $2 million of our 6.5% Senior Notes due 2017 for $1 million . Subsequent to December 31, 2015, we closed certain asset divestitures for proceeds of approximately $138 million . We also executed sales agreements for other asset divestitures with expected proceeds of approximately $586 million . The asset divestitures cover various operating areas.

Basis of Presentation and Sum34

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Basis of Accounting Policy	Basis of Presentation The accompanying consolidated financial statements of Chesapeake were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated.
Accounting Estimates Policy	Accounting Estimates The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates. Estimates of oil and natural gas reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in oil, natural gas or NGL prices could result in actual results differing significantly from our estimates.
Consolidation, Including Noncontrolling Interests, Policy	Consolidation Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 14 for further discussion of our investments. Undivided interests in oil and natural gas exploration and production joint ventures are consolidated on a proportionate basis. Noncontrolling Interests Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.
Consolidation, Variable Interest Entity, Policy	Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any reconsideration events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.
Cash and Cash Equivalents, Policy	Accounts Payable Included in accounts payable as of December 31, 2015 and 2014 are liabilities of approximately $60 million and $333 million , respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Cash and Cash Equivalents and Restricted Cash For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. As of December 31, 2014, our restricted cash consisted of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T). The repurchase and cancellation of the outstanding preferred shares of CHK C-T eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion.
Accounts Receivable, Policy	Accounts Receivable Our accounts receivable are primarily from purchasers of oil, natural gas and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables that we believe may be uncollectible. During 2015, 2014 and 2013, we recognized $4 million , $2 million and $2 million of bad debt expense related to potentially uncollectible receivables. Accounts receivable as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 696 $ 1,340 Joint interest 230 691 Other 226 226 Allowance for doubtful accounts (23 ) (21 ) Total accounts receivable, net $ 1,129 $ 2,236
Oil and Natural Gas Properties Policy	Oil and Natural Gas Properties Chesapeake follows the full cost method of accounting under which all costs associated with oil and natural gas property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information – Supplemental Disclosures About Oil, Natural Gas and NGL Producing Activities ). Capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. Estimates of our proved reserves as of December 31, 2015 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 59% by volume and 77% by value of these proved reserves estimates as of December 31, 2015 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis. Proceeds from the sale of oil and natural gas properties are accounted for as reductions of capitalized costs unless these sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized. The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties that portion of our leasehold which can be associated with proved reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned. The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and the year in which the associated costs were incurred. Year of Acquisition 2015 2014 2013 Prior Total ($ in millions) Leasehold cost $ 121 $ 651 $ 200 $ 4,304 $ 5,276 Exploration cost 68 13 15 58 154 Capitalized interest 331 303 259 475 1,368 Total $ 520 $ 967 $ 474 $ 4,837 $ 6,798 We also review, on a quarterly basis, the carrying value of our oil and natural gas properties under the full cost accounting rules of the Securities and Exchange Commission (SEC). This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for oil and natural gas derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of oil, natural gas and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. These prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2015, none of our open derivative instruments were designated as cash flow hedges. Our oil and natural gas hedging activities are discussed in Note 11. Two primary factors impacting the ceiling test are reserves levels and oil, natural gas and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of oil and natural gas reserves and/or an extended increase or decrease in prices can have a material impact on the present value of our estimated future net revenues. Any excess of the net book value over the ceiling is written off as an expense. We account for seismic costs as part of our oil and natural gas properties. Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. These costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.
Other Property and Equipment, Policy	Other Property and Equipment Other property and equipment consists primarily of natural gas compressors, buildings and improvements, land, vehicles, computer and office equipment, oil and natural gas gathering systems and treating plants. We have no remaining oilfield services equipment as a result of the spin-off of our oilfield services business in 2014, as discussed in Note 13. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 16 for further discussion of our gains and losses on the sales of other property and equipment for the years ended 2015, 2014 and 2013 and a summary of our other property and equipment held for sale as of December 31, 2015 and 2014. Other property and equipment costs, excluding land, are depreciated on a straight-line basis. Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2015, 2014 and 2013, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 17 for further discussion of these impairments.
Capitalized Interest, Policy	Capitalized Interest Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average borrowing rate of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.
Accounts Payable Policy	Accounts Payable Included in accounts payable as of December 31, 2015 and 2014 are liabilities of approximately $60 million and $333 million , respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts. Cash and Cash Equivalents and Restricted Cash For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at the date of purchase to be cash equivalents. As of December 31, 2014, our restricted cash consisted of the balance required to be maintained by the terms of the agreement governing the activities of CHK Cleveland Tonkawa, L.L.C. (CHK C-T). The repurchase and cancellation of the outstanding preferred shares of CHK C-T eliminated the restricted cash maintenance requirement related to this entity. See Note 8 for further discussion.
Debt Issuance and Hedging Facility Costs, Policy	Debt Issuance and Hedging Facility Costs Included in other long-term assets are costs associated with the issuance of our senior notes, revolving credit facility and hedging facility. The remaining unamortized issuance costs as of December 31, 2015 and 2014 totaled $74 million and $130 million , respectively, and are being amortized over the life of the applicable debt instrument or credit facility using the effective interest method.
Environmental Remediation Costs, Policy	Environmental Remediation Costs Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.
Asset Retirement Obligations, Policy	Asset Retirement Obligations We recognize liabilities for obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For oil and natural gas properties, this is the period in which an oil or natural gas well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural gas properties. See Note 20 for further discussion of asset retirement obligations.
Revenue Recognition, Policy	Revenue Recognition Oil, Natural Gas and NGL Sales . Revenue from the sale of oil, natural gas and NGL is recognized when title passes, net of royalties due to third parties. Natural Gas Imbalances . We follow the sales method of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance net liability position as of December 31, 2015 and 2014 was $10 million and $12 million , respectively. Marketing, Gathering and Compression Sales. Chesapeake takes title to the oil, natural gas and NGL it purchases from other interest owners at defined delivery points and delivers the product to third parties, at which time revenues are recorded. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including credit risk mitigation and to help meet certain of our pipeline delivery commitments. In circumstances where we act as a principal rather than an agent, Chesapeake's results of operations related to its oil, natural gas and NGL marketing activities are presented on a gross basis. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated. Oilfield Services Revenue. Prior to the spin-off of our oilfield services business in June 2014, we reported oilfield services revenue. Our former oilfield services operating segment was responsible for contract drilling, hydraulic fracturing, rentals, trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Revenues were recognized upon completion stages for our contract drilling, hydraulic fracturing and other oilfield services. Revenue was recognized ratably over the term of the rental for our oilfield rental services. Oilfield trucking services were priced on a per barrel basis based on mileage and revenue was recognized as services were performed.
Fair Value Measurements, Policy	Fair Value Measurements Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, (i.e., an exit price). To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority. The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost). The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these instruments.
Derivatives, Policy	Derivatives Derivative instruments are recorded on our consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are followed. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Locked-in gains and losses of settled cash flow hedges are recorded in accumulated other comprehensive income and are transferred to earnings in the month of production. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge ineffectiveness and are recognized currently in earnings. Locked-in gains and losses related to settled fair value hedges are amortized as an adjustment to interest expense over the remaining term of the related debt instrument. We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in our consolidated statements of operations within oil, natural gas and NGL sales and interest expense, respectively. From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. The changes in fair value of the embedded derivative and the settlements are recognized in our consolidated statements of operations within marketing, gathering and compression sales. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for the offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets. We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.
Share-Based Compensation, Policy	Share-Based Compensation Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as general and administrative expense in the consolidated statements of operations. To the extent compensation expense relates to employees directly involved in the acquisition of oil and natural gas leasehold and exploration and development activities, these amounts are capitalized to oil and natural gas properties. Amounts not capitalized to oil and natural gas properties are recognized as general and administrative expenses, oil, natural gas and NGL production expenses, or marketing, gathering and compression expenses, based on the employees involved in those activities. Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.
Reclassifications, Policy	Reclassifications Certain reclassifications have been made to our consolidated financial statements for 2014 and 2013 to conform to the presentation used for the 2015 consolidated financial statements. Beginning in the fourth quarter of 2015, we have reclassified our presentation of third party transportation and gathering costs to report the costs as a component of operating expenses in the accompanying statements of operations. Previously, these costs were reflected as deductions to oil, natural gas and NGL sales. The net effect of this reclassification did not impact our previously reported net income, stockholders’ equity or cash flows; however, previously reported oil, natural gas and NGL sales have increased from the amounts previously reported, and total operating expenses have increased by those same amounts. The following table reflects the reclassifications made: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL sales, previously reported $ 8,180 $ 7,052 Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL sales, as currently reported $ 10,354 $ 8,626 The corresponding amounts have been reflected in oil, natural gas and NGL gathering, processing and transportation expenses for 2014 and 2013 as shown below: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL gathering, processing and transportation expenses, previously reported $ — $ — Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL gathering, processing and transportation expenses, as currently reported $ 2,174 $ 1,574 In November 2015, the FASB issued an accounting standards update, which requires deferred tax liabilities and assets be classified as non-current in a classified statement of financial position. This standards update is effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted and we elected to adopt the updated standard effective December 31, 2015. This change in accounting principle is preferable since the current presentation does not generally align with the time period in which the deferred tax amounts are expected to be recognized. A retrospective change to the December 31, 2014 consolidated balance sheet as previously presented is required pursuant to this updated standard. We retrospectively adjusted the December 31, 2014 consolidated balance sheet and reclassified $207 million of our current deferred income tax liabilities to noncurrent deferred income tax liabilities.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	12 Months Ended
	Dec. 31, 2015
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Consolidation, Variable Interest Entity, Policy	Variable Interest Entities VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both our consolidated and unconsolidated VIEs to determine if any reconsideration events have occurred that could cause the primary beneficiary to change. See Note 15 for further discussion of VIEs. We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Impairments (Policies)

Impairments (Policies)	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Impairment or Disposal of Long-Lived Assets, Policy	Our proved oil and natural gas properties are subject to quarterly full cost ceiling tests.

Recently Issued Accounting St37

Recently Issued Accounting Standards (Policies)	12 Months Ended
	Dec. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements, Policy	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. We are evaluating the impact of this guidance on our consolidated financial statements. In April 2015, the FASB issued an accounting standards update on the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements. In August 2015, the FASB issued an accounting standards update which allows for debt issuance costs related to line-of-credit arrangements to be presented as an asset and subsequently amortized ratably over the term of the line-of-credit arrangements, regardless of whether there are any outstanding borrowings on the line-of-credit arrangements. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements.

Basis of Presentation and Sum38

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable	Accounts receivable as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 696 $ 1,340 Joint interest 230 691 Other 226 226 Allowance for doubtful accounts (23 ) (21 ) Total accounts receivable, net $ 1,129 $ 2,236
Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization	The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2015 and the year in which the associated costs were incurred. Year of Acquisition 2015 2014 2013 Prior Total ($ in millions) Leasehold cost $ 121 $ 651 $ 200 $ 4,304 $ 5,276 Exploration cost 68 13 15 58 154 Capitalized interest 331 303 259 475 1,368 Total $ 520 $ 967 $ 474 $ 4,837 $ 6,798
Schedule of Revisions to Oil, Natural Gas and NGL Sales, Reported	The following table reflects the reclassifications made: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL sales, previously reported $ 8,180 $ 7,052 Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL sales, as currently reported $ 10,354 $ 8,626 The corresponding amounts have been reflected in oil, natural gas and NGL gathering, processing and transportation expenses for 2014 and 2013 as shown below: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL gathering, processing and transportation expenses, previously reported $ — $ — Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL gathering, processing and transportation expenses, as currently reported $ 2,174 $ 1,574
Schedule of Revisions to Oil, Natural Gas and NGL Transportation and Other Expenses	The following table reflects the reclassifications made: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL sales, previously reported $ 8,180 $ 7,052 Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL sales, as currently reported $ 10,354 $ 8,626 The corresponding amounts have been reflected in oil, natural gas and NGL gathering, processing and transportation expenses for 2014 and 2013 as shown below: Years Ended December 31, 2014 2013 $ in millions Oil, natural gas and NGL gathering, processing and transportation expenses, previously reported $ — $ — Reclassification of oil, natural gas and NGL gathering, processing and transportation expenses 2,174 1,574 Oil, natural gas and NGL gathering, processing and transportation expenses, as currently reported $ 2,174 $ 1,574

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Antidilutive Securities Excluded From Computation Of Earnings Per Share	For the years ended December 31, 2015, 2014 and 2013, shares of the following securities and associated adjustments to net income, representing dividends on preferred stock and allocated earnings on participating securities, were excluded from the calculation of diluted EPS as the effect was antidilutive. Net Income Adjustments Shares ($ in millions) (in millions) Year Ended December 31, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 86 59 5.75% cumulative convertible preferred stock (series A) $ 63 42 5.00% cumulative convertible preferred stock (series 2005B) $ 10 6 4.50% cumulative convertible preferred stock $ 12 6 Participating securities $ — 1 Year Ended December 31, 2014 Participating securities $ 26 3 Year Ended December 31, 2013 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 86 56 5.75% cumulative convertible preferred stock (series A) $ 63 40 5.00% cumulative convertible preferred stock (series 2005B) $ 10 5 4.50% cumulative convertible preferred stock $ 12 6 Participating securities $ 10 5
Schedule of Earnings Per Share, Basic and Diluted	For the year ended December 31, 2014, all outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the year ended December 31, 2014 is as follows: Income (Numerator) Weighted Average Shares (Denominator) Per Share Amount (in millions, except per share data) For the Year Ended December 31, 2014: Basic EPS $ 1,273 659 $ 1.93 Effect of Dilutive Securities: Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: Common shares assumed issued for 5.75% cumulative convertible preferred stock 86 59 Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) 63 42 Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B) 10 6 Common shares assumed issued for 4.50% cumulative convertible preferred stock 12 6 Diluted EPS $ 1,444 772 $ 1.87

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Debt	Our long-term debt consisted of the following as of December 31, 2015 and 2014: December 31, 2015 December 31, 2014 Principal Amount Carrying Principal Carrying ($ in millions) 3.25% senior notes due 2016 $ 381 $ 381 $ 500 $ 500 6.25% euro-denominated senior notes due 2017 (a)(b) 329 329 416 416 6.5% senior notes due 2017 (b) 453 452 660 659 7.25% senior notes due 2018 (b) 538 538 669 669 Floating rate senior notes due 2019 (b) 1,104 1,104 1,500 1,500 6.625% senior notes due 2020 (b) 822 822 1,300 1,300 6.875% senior notes due 2020 (b) 304 303 500 497 6.125% senior notes due 2021 (b) 589 589 1,000 1,000 5.375% senior notes due 2021 (b) 286 286 700 700 4.875% senior notes due 2022 (b) 639 639 1,500 1,500 8.00% senior secured second lien notes due 2022 (b) 2,425 3,584 — — 5.75% senior notes due 2023 (b) 384 384 1,100 1,100 2.75% contingent convertible senior notes due 2035 (c)(d) 2 2 396 381 2.5% contingent convertible senior notes due 2037 (b)(c)(d) 1,110 1,026 1,168 1,024 2.25% contingent convertible senior notes due 2038 (b)(c)(d) 340 289 347 279 Revolving credit facility — — — — Interest rate derivatives (e) — 7 — 10 Total debt, net 9,706 10,735 11,756 11,535 Less current maturities of long-term debt, net (f) (381 ) (381 ) (396 ) (381 ) Total long-term debt, net $ 9,325 $ 10,354 $ 11,360 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.0862 to €1.00 and $1.2098 to €1.00 as of December 31, 2015 and 2014, respectively. See Foreign Currency Derivatives in Note 11 for information on our related foreign currency derivatives. (b) In 2015, a portion of these outstanding senior unsecured notes were exchanged for newly issued 8.00% Senior Secured Second Lien Notes due 2022. See Chesapeake Senior Secured Second Lien Notes and Chesapeake Senior Notes and Contingent Convertible Senior Notes below for further discussion regarding these transactions. (c) The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows: Holders’ Demand Repurchase Rights . The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five , ten , fifteen and twenty years before the maturity date. Optional Conversion by Holders . At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the fourth quarter of 2015, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the first quarter of 2016 under this provision. The notes are also convertible, at the holder’s option, during specified five -day periods if the trading price of the notes is below certain levels determined by reference to the trading price of our common stock. The notes were not convertible under this provision during the years ended December 31, 2015, 2014 or 2013. In general, upon conversion of a contingent convertible senior note, the holder will receive cash equal to the principal amount of the note and common stock for the note’s conversion value in excess of the principal amount. Contingent Interest. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years during certain periods if the average trading price of the notes exceeds the threshold defined in the indenture. The holders’ demand repurchase dates, the common stock price conversion threshold amounts (as adjusted to give effect to cash dividends on our common stock) and the ending date of the first six-month period in which contingent interest may be payable for the contingent convertible senior notes are as follows: Contingent Convertible Senior Notes Holders' Demand Repurchase Dates Common Stock Price Conversion Thresholds Contingent Interest First Payable (if applicable) 2.75% due 2035 November 15, 2020, 2025, 2030 $ 45.02 May 14, 2016 2.5% due 2037 May 15, 2017, 2022, 2027, 2032 $ 59.44 November 14, 2017 2.25% due 2038 December 15, 2018, 2023, 2028, 2033 $ 100.20 June 14, 2019 Optional Redemption by the Company. We may redeem the contingent convertible senior notes once they have been outstanding for ten years at a redemption price of 100% of the principal amount of the notes, payable in cash. (d) Discount as of December 31, 2015 and 2014 included $133 million and $224 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (e) See Interest Rate Derivatives in Note 11 for further discussion related to these instruments. (f) As of December 31, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016. As of December 31, 2014, there was $15 million of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (c) above, holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercised their demand repurchase rights on November 15, 2015, which required us to repurchase such holders’ notes.
Schedule of Maturities of Long-term Debt	Total principal amount of debt maturities, using the earliest demand repurchase date for contingent convertible senior notes, for the five years ended after December 31, 2015 and thereafter are as follows: Principal Amount of Debt Securities ($ in millions) 2016 $ 381 2017 1,892 2018 878 2019 1,104 2020 1,128 2021 and thereafter 4,323 Total $ 9,706
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. December 31, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 381 $ 366 $ 381 $ 396 Long-term debt (Level 1) $ 10,347 $ 3,735 $ 11,144 $ 11,656

Contingencies and Commitments41

Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Operating Leases Commitments	As of December 31, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below. December 31, ($ in millions) 2016 $ 160 2017 114 2018 6 Total $ 280 Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below. December 31, 2015 ($ in millions) 2016 $ 4 2017 2 2018 2 2019 1 Total $ 9 The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below. December 31, ($ in millions) 2016 $ 1,932 2017 1,944 2018 1,742 2019 1,443 2020 1,111 2021 – 2099 5,793 Total $ 13,965
Gathering, Processing and Transportation Commitments	As of December 31, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below. December 31, ($ in millions) 2016 $ 160 2017 114 2018 6 Total $ 280 Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below. December 31, 2015 ($ in millions) 2016 $ 4 2017 2 2018 2 2019 1 Total $ 9 The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below. December 31, ($ in millions) 2016 $ 1,932 2017 1,944 2018 1,742 2019 1,443 2020 1,111 2021 – 2099 5,793 Total $ 13,965
Drilling Service Contracts Commitments	As of December 31, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments are detailed below. December 31, ($ in millions) 2016 $ 160 2017 114 2018 6 Total $ 280 Future operating lease commitments related to other property and equipment are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below. December 31, 2015 ($ in millions) 2016 $ 4 2017 2 2018 2 2019 1 Total $ 9 The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, credits for third-party volumes or future costs under cost-of-service agreements, are presented below. December 31, ($ in millions) 2016 $ 1,932 2017 1,944 2018 1,742 2019 1,443 2020 1,111 2021 – 2099 5,793 Total $ 13,965
Pressure Pumping Contracts Commitments	As of December 31, 2015 , the aggregate undiscounted minimum future payments under this agreement are detailed below. December 31, 2015 ($ in millions) 2016 $ 122 2017 64 Total $ 186

Other Liabilities (Tables)

Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	Other current liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) Revenues and royalties due others $ 500 $ 1,176 Accrued drilling and production costs 212 385 Joint interest prepayments received 169 189 Accrued compensation and benefits 264 344 Other accrued taxes 21 55 Accrued dividends — 101 Bank of New York Mellon legal accrual 439 100 Oklahoma royalty settlement — 119 Minimum gathering volume commitment (a) 201 141 Other 413 451 Total other current liabilities $ 2,219 $ 3,061 ____________________________________________ (a) Minimum gathering volume commitments are presented on a gross basis. We have recorded receivables from certain of our working interest partners for their proportionate share of the liabilities of $27 million and $21 million as of December 31, 2015 and 2014, respectively.
Other Long-Term Liabilities	Other long-term liabilities as of December 31, 2015 and 2014 are detailed below. December 31, 2015 2014 ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 190 $ 220 CHK C-T ORRI conveyance obligation (b) — 135 Financing obligations 29 30 Unrecognized tax benefits 64 45 Other 126 249 Total other long-term liabilities $ 409 $ 679 ____________________________________________ (a) $21 million and $14 million of the total $211 million and $234 million obligations are recorded in other current liabilities as of December 31, 2015 and 2014, respectively. See Noncontrolling Interests in Note 8 for further discussion of the conveyance obligation. (b) $23 million of the total $158 million obligation is recorded in other current liabilities as of December 31, 2014. In 2015, we sold the oil and natural gas properties held by CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and eliminated our ORRI obligation attributable to CHK C-T. See Noncontrolling Interests in Note 8 for further discussion of the transaction.

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The components of the income tax provision (benefit) for each of the periods presented below are as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Current Federal $ — $ — $ — State (36 ) 47 22 Current Income Taxes (36 ) 47 22 Deferred Federal (4,385 ) 1,115 502 State (42 ) (18 ) 24 Deferred Income Taxes (4,427 ) 1,097 526 Total $ (4,463 ) $ 1,144 $ 548
Schedule of Effective Income Tax Rate Reconciliation	The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons: Years Ended December 31, 2015 2014 2013 ($ in millions) Income tax expense (benefit) at the federal statutory rate (35%) $ (6,684 ) $ 1,120 $ 505 State income taxes (net of federal income tax benefit) (406 ) 68 88 Remeasurement of state deferred tax liabilities — (114 ) (38 ) Change in valuation allowance 2,727 74 (12 ) Other (100 ) (4 ) 5 Total $ (4,463 ) $ 1,144 $ 548
Schedule of Deferred Tax Assets and Liabilities	Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows: Years Ended December 31, 2015 2014 ($ in millions) Deferred tax liabilities: Property, plant and equipment $ — $ (3,829 ) Volumetric production payments (802 ) (1,023 ) Carrying value of debt — (443 ) Derivative instruments (294 ) (428 ) Other (74 ) (114 ) Deferred tax liabilities (1,170 ) (5,837 ) Deferred tax assets: Property, plant and equipment 1,140 — Net operating loss carryforwards (carrybacks) 1,556 945 Carrying value of debt 535 — Asset retirement obligations 174 165 Investments 132 84 Accrued liabilities 332 239 Other 250 234 Deferred tax assets 4,119 1,667 Valuation allowance (2,949 ) (222 ) Net deferred tax assets 1,170 1,445 Net deferred tax assets (liabilities) $ — $ (4,392 ) Reflected in accompanying balance sheets as: Non-current deferred income tax liability $ — $ (4,392 ) Total $ — $ (4,392 )
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2015 2014 2013 ($ in millions) Unrecognized tax benefits at beginning of period $ 303 $ 644 $ 599 Additions based on tax positions related to the current year 27 13 15 Additions to tax positions of prior years — — 30 Reductions to tax positions of prior years (50 ) (354 ) — Unrecognized tax benefits at end of period $ 280 $ 303 $ 644

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Our equity method investees are considered related parties. During 2015, 2014 and 2013, we had the following transactions with our equity method investees: Years Ended December 31, 2015 2014 2013 ($ in millions) Sales (a) $ — $ — $ 666 Services (b) $ 65 $ 220 $ 397 ___________________________________________ (a) In 2013, Chesapeake sold produced gas to our 30% -owned investee, Twin Eagle Resource Management LLC (Twin Eagle). We sold our investment in Twin Eagle in 2014. (b) Hydraulic fracturing and other services are provided to us by FTS International, Inc. in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Common Stock	The following is a summary of the changes in our common shares issued for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 (in thousands) Shares issued as of January 1 664,944 666,192 666,468 Restricted stock issuances (net of forfeitures and cancellations) (a) (163 ) (2,529 ) (599 ) Stock option exercises 15 1,281 323 Shares issued as of December 31 664,796 664,944 666,192 ___________________________________________ (a) The amount for 2014 reflects forfeitures upon the June 2014 spin-off of our oilfield services business.
Schedule of Stock by Class,Preferred Stock Conversion Terms	The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2015, 2014 and 2013: 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2015, 2014 and 2013 and shares outstanding as of December 31, 2015, 2014 and 2013 1,497 1,100 2,559 2,096 Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2015: Preferred Stock Series Issue Date Liquidation Preference per Share Holder's Conversion Right Conversion Rate Conversion Price Company's Conversion Right From Company's Market Conversion Trigger (a) 5.75% cumulative convertible non-voting May and June 2010 $ 1,000 Any time 39.6526 $ 25.2190 May 17, 2015 $ 32.7847 5.75% (series A) cumulative convertible non-voting May 2010 $ 1,000 Any time 38.3186 $ 26.0970 May 17, 2015 $ 33.9261 4.50% cumulative convertible September 2005 $ 100 Any time 2.4561 $ 40.7152 September 15, 2010 $ 52.9298 5.00% cumulative convertible (series 2005B) November 2005 $ 100 Any time 2.7745 $ 36.0431 November 15, 2010 $ 46.8560 ___________________________________________ (a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.
Schedule of Stock by Class, Preferred Stock Shares Outstanding	The following reflects the shares outstanding of our preferred stock for the years ended December 31, 2015, 2014 and 2013: 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2015, 2014 and 2013 and shares outstanding as of December 31, 2015, 2014 and 2013 1,497 1,100 2,559 2,096 Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2015: Preferred Stock Series Issue Date Liquidation Preference per Share Holder's Conversion Right Conversion Rate Conversion Price Company's Conversion Right From Company's Market Conversion Trigger (a) 5.75% cumulative convertible non-voting May and June 2010 $ 1,000 Any time 39.6526 $ 25.2190 May 17, 2015 $ 32.7847 5.75% (series A) cumulative convertible non-voting May 2010 $ 1,000 Any time 38.3186 $ 26.0970 May 17, 2015 $ 33.9261 4.50% cumulative convertible September 2005 $ 100 Any time 2.4561 $ 40.7152 September 15, 2010 $ 52.9298 5.00% cumulative convertible (series 2005B) November 2005 $ 100 Any time 2.7745 $ 36.0431 November 15, 2010 $ 46.8560 ___________________________________________ (a) Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the applicable conversion date if there are less than 250,000 shares of 4.50% or 5.00% (Series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (Series A) preferred stock outstanding.
Schedule of Accumulated Other Comprehensive Income (Loss)	For the years ended December 31, 2015 and 2014, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Investments Net Change ($ in millions) Balance, December 31, 2014 $ (143 ) $ — $ (143 ) Other comprehensive income before reclassifications 20 — 20 Amounts reclassified from accumulated other comprehensive income 24 — 24 Net other comprehensive income 44 — 44 Balance, December 31, 2015 $ (99 ) $ — $ (99 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 1 — 1 Amounts reclassified from accumulated other comprehensive income 23 (5 ) 18 Net other comprehensive income 24 (5 ) 19 Balance, December 31, 2014 $ (143 ) $ — $ (143 )
Reclassification out of Accumulated Other Comprehensive Income	For the years ended December 31, 2015 and 2014, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statements of operations are detailed below. Details About Accumulated Other Comprehensive Income (Loss) Components Affected Line Item in the Statement Where Net Income is Presented Amounts Reclassified ($ in millions) Year Ended December 31, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 23 Foreign currency derivative Gain (loss) on purchases or exchanges of debt 1 Total reclassifications for the period, net of tax $ 24 Year Ended December 31, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 23 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 18
Distributions Made to Limited Partner, by Distribution	For the years ended December 31, 2015, 2014 and 2013, the Trust declared and paid the following distributions: Production Period Distribution Date Cash Distribution per Common Unit Cash Distribution per Subordinated Unit June 2015 – August 2015 November 30, 2015 $ 0.3232 $ — March 2015 – May 2015 August 31, 2015 $ 0.3579 $ — December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — June 2014 – August 2014 December 1, 2014 $ 0.5079 $ — March 2014 – May 2014 August 29, 2014 $ 0.5796 $ — December 2013 – February 2014 May 30, 2014 $ 0.6454 $ — September 2013 – November 2013 March 3, 2014 $ 0.6624 $ — June 2013 – August 2013 November 29, 2013 $ 0.6671 $ — March 2013 – May 2013 August 29, 2013 $ 0.6900 $ 0.1432 December 2012 – February 2013 May 31, 2013 $ 0.6900 $ 0.3010 September 2012 – November 2012 March 1, 2013 $ 0.6700 $ 0.3772

Share-Based Compensation (Table

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-Based Compensation, Restricted Stock and Restricted Stock Units Activity	A summary of the changes in unvested restricted stock during 2015, 2014 and 2013 is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2015 10,091 $ 21.20 Granted 7,095 $ 13.90 Vested (4,157 ) $ 21.70 Forfeited (2,574 ) $ 16.98 Unvested restricted stock as of December 31, 2015 10,455 $ 17.31 Unvested restricted stock as of January 1, 2014 13,400 $ 23.38 Granted 5,049 $ 25.92 Vested (4,803 ) $ 27.17 Forfeited (3,555 ) $ 28.09 Unvested restricted stock as of December 31, 2014 10,091 $ 21.20 Unvested restricted stock as of January 1, 2013 18,899 $ 23.72 Granted 9,189 $ 19.68 Vested (12,897 ) $ 21.32 Forfeited (1,791 ) $ 22.86 Unvested restricted stock as of December 31, 2013 13,400 $ 23.38
Equity-Classified Share-Based Payment Award Valuation Assumptions	The Company utilized the Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs: Volatility 55.76 % Risk-free interest rate 1.06 % Dividend yield for value of awards — % The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2015: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 %
Schedule of Share-Based Compensation, Stock Options, Activity	The following table provides information related to stock option activity for 2015, 2014 and 2013: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding at January 1, 2015 4,599 $ 19.55 7.03 $ 5 Granted 1,208 $ 18.37 Exercised (14 ) $ 18.13 $ — Expired (416 ) $ 18.46 Forfeited — $ — Outstanding at December 31, 2015 5,377 $ 19.37 5.80 $ — Exercisable at December 31, 2015 2,045 $ 19.61 5.07 $ — Outstanding at January 1, 2014 5,268 $ 19.28 6.66 $ 41 Granted 994 $ 24.43 Exercised (1,322 ) $ 18.71 $ 11 Expired (28 ) $ 18.97 Forfeited (313 ) $ 21.05 Outstanding at December 31, 2014 4,599 $ 19.55 7.03 $ 5 Exercisable at December 31, 2014 1,304 $ 18.71 5.70 $ 1 Outstanding at January 1, 2013 481 $ 12.69 0.96 $ 2 Granted 5,264 $ 19.32 Exercised (346 ) $ 10.82 $ 3 Expired (131 ) $ 19.31 Outstanding at December 31, 2013 5,268 $ 19.28 6.66 $ 41 Exercisable at December 31, 2013 1,552 $ 18.82 1.97 $ 13 ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
Equity-Classified Stock-Based Compensation	We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ 43 $ 46 $ 60 Oil and natural gas properties 23 29 52 Oil, natural gas and NGL production expenses 18 18 21 Marketing, gathering and compression expenses 5 6 7 Oilfield services expenses — 5 10 Total $ 89 $ 104 $ 150 We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ (19 ) $ (4 ) $ 34 Restructuring and other termination costs (19 ) (19 ) 29 Marketing, gathering and compression (1 ) — 2 Oil and natural gas properties (2 ) 3 9 Oil, natural gas and NGL production expenses — — 2 Oilfield services expenses — — 1 Total $ (41 ) $ (20 ) $ 77
Liability-Classified Share-Based Payment Award Valuation Assumptions	The Company utilized the Monte Carlo simulation for the TSR performance measure and the following assumptions to determine the grant date fair value of the PSUs: Volatility 55.76 % Risk-free interest rate 1.06 % Dividend yield for value of awards — % The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in 2015: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 %
Schedule of Nonvested Performance-based Units Activity	The following table presents a summary of our 2015, 2014 and 2013 PSU awards: Units Fair Value as of Grant Date Fair Value (a) Liability for Vested Amount (a) ($ in millions) 2015 Awards: Payable 2018 696,683 $ 13 2 1 2014 Awards: Payable 2017 609,637 $ 16 — — 2013 Awards: Payable 2016 1,701,941 $ 35 $ 4 $ 4 ___________________________________________ (a) As of December 31, 2015 .
Liability-Classified Stock-Based Compensation	We recognized the following compensation costs related to restricted stock and stock options for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ 43 $ 46 $ 60 Oil and natural gas properties 23 29 52 Oil, natural gas and NGL production expenses 18 18 21 Marketing, gathering and compression expenses 5 6 7 Oilfield services expenses — 5 10 Total $ 89 $ 104 $ 150 We recognized the following compensation costs (credits) related to PSUs for the years ended December 31, 2015, 2014 and 2013: Years Ended December 31, 2015 2014 2013 ($ in millions) General and administrative expenses $ (19 ) $ (4 ) $ 34 Restructuring and other termination costs (19 ) (19 ) 29 Marketing, gathering and compression (1 ) — 2 Oil and natural gas properties (2 ) 3 9 Oil, natural gas and NGL production expenses — — 2 Oilfield services expenses — — 1 Total $ (41 ) $ (20 ) $ 77

Derivative and Hedging Activi47

Derivative and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of December 31, 2015 and 2014 are provided below. December 31, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 13.5 $ 144 12.5 $ 471 Three-way collars — — 4.4 40 Call options 19.2 (7 ) 35.8 (89 ) Basis protection swaps — — — — Total oil 32.7 $ 137 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 500 $ 229 275 $ 281 Three-way collars — — 207 165 Call options 295 (99 ) 193 (170 ) Basis protection swaps 57 — 60 23 Total natural gas 852 $ 130 735 $ 299 Total estimated fair value $ 267 $ 721
Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets	The following table presents the fair value and location of each classification of derivative instrument included in the consolidated balance sheets as of December 31, 2015 and 2014 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Consolidated Balance Sheet Net Fair Value Presented in Consolidated Balance Sheet ($ in millions) As of December 31, 2015 Commodity Contracts: Short-term derivative asset $ 381 $ (66 ) $ 315 Long-term derivative asset — — — Short-term derivative liability (106 ) 66 (40 ) Long-term derivative liability (8 ) — (8 ) Total commodity contracts 267 — 267 Foreign Currency Contracts: (a) Long-term derivative liability (52 ) — (52 ) Total foreign currency contracts (52 ) — (52 ) Supply Contracts: Short-term derivative asset 51 — 51 Long-term derivative asset 246 — 246 Total supply contracts 297 — 297 Total derivatives $ 512 $ — $ 512 Balance Sheet Classification Gross Fair Value Amounts Netted in Consolidated Balance Sheet Net Fair Value Presented in Consolidated Balance Sheet As of December 31, 2014 Commodity Contracts: Short-term derivative asset $ 973 $ (95 ) $ 878 Long-term derivative asset 16 (10 ) 6 Short-term derivative liability (105 ) 95 (10 ) Long-term derivative liability (163 ) 10 (153 ) Total commodity contracts 721 — 721 Interest Rate Contracts: Short-term derivative liability (5 ) — (5 ) Long-term derivative liability (12 ) — (12 ) Total interest rate contracts (17 ) — (17 ) Foreign Currency Contracts: (a) Long-term derivative liability (53 ) — (53 ) Total foreign currency contracts (53 ) — (53 ) Supply Contracts: Short-term derivative asset 1 — 1 Long-term derivative asset — — — Total supply contracts 1 — 1 Total derivatives $ 652 $ — $ 652 ____________________________________________ (a) Designated as cash flow hedging instruments
Schedule of Derivative Instruments, Natural Gas and Oil Sales	The components of oil, natural gas and NGL revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Oil, natural gas and NGL revenues $ 4,767 $ 9,336 $ 8,497 Gains (losses) on undesignated oil and natural gas derivatives 661 1,055 443 Losses on terminated cash flow hedges (37 ) (37 ) (314 ) Total oil, natural gas and NGL revenues $ 5,391 $ 10,354 $ 8,626 The components of marketing, gathering and compression revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Marketing, gathering and compression revenues $ 7,077 $ 12,224 $ 9,559 Gains on undesignated supply contract derivatives 296 1 — Total marketing, gathering and compression revenues $ 7,373 $ 12,225 $ 9,559
Schedule of Derivative Instruments, Marketing, Gathering and Compression Sales	The components of oil, natural gas and NGL revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Oil, natural gas and NGL revenues $ 4,767 $ 9,336 $ 8,497 Gains (losses) on undesignated oil and natural gas derivatives 661 1,055 443 Losses on terminated cash flow hedges (37 ) (37 ) (314 ) Total oil, natural gas and NGL revenues $ 5,391 $ 10,354 $ 8,626 The components of marketing, gathering and compression revenues for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Marketing, gathering and compression revenues $ 7,077 $ 12,224 $ 9,559 Gains on undesignated supply contract derivatives 296 1 — Total marketing, gathering and compression revenues $ 7,373 $ 12,225 $ 9,559
Interest Income And Interest Expense Disclosure	The components of interest expense for the years ended December 31, 2015, 2014 and 2013 are presented below. Years Ended December 31, 2015 2014 2013 ($ in millions) Interest expense on senior notes $ 682 $ 704 $ 740 Interest expense on term loan — 36 116 Amortization of loan discount, issuance costs and other 59 42 91 Interest expense on credit facilities 12 28 38 Gains on terminated fair value hedges (3 ) (3 ) (5 ) (Gains) losses on undesignated interest rate derivatives (9 ) (81 ) 63 Capitalized interest (424 ) (637 ) (816 ) Total interest expense $ 317 $ 89 $ 227
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below. Years Ended December 31, 2015 2014 2013 Before Tax After Tax Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (231 ) $ (143 ) $ (269 ) $ (167 ) $ (304 ) $ (189 ) Net change in fair value 32 20 1 1 3 2 Losses reclassified to income 39 24 37 23 32 20 Balance, end of period $ (160 ) $ (99 ) $ (231 ) $ (143 ) $ (269 ) $ (167 )
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Interest rate liabilities — — — — Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2015 and 2014 is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 100 316 Total purchases, issuances, sales and settlements: Settlements (137 ) (20 ) Ending balance as of December 31, 2015 $ (91 ) $ 297 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 292 1 Total purchases, issuances, sales and settlements: Settlements 136 — Transfers (b) (4 ) — Ending balance as of December 31, 2014 $ (54 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 100 $ 292 $ 296 $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ 43 $ 262 $ 296 $ — (b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values. The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 )
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Interest rate liabilities — — — — Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2015 and 2014 is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 100 316 Total purchases, issuances, sales and settlements: Settlements (137 ) (20 ) Ending balance as of December 31, 2015 $ (91 ) $ 297 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 292 1 Total purchases, issuances, sales and settlements: Settlements 136 — Transfers (b) (4 ) — Ending balance as of December 31, 2014 $ (54 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 100 $ 292 $ 296 $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ 43 $ 262 $ 296 $ — (b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values.
Fair Value Inputs, Assets, Quantitative Information	The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of December 31, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value December 31, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 26.87% – 43.08% 35.52% $ (7 ) Supply contracts (b) Oil price volatility curves 20.01% – 43.81% 24.07% $ 297 Natural gas trades (a) Natural gas price volatility curves 19.84% – 73.05% 34.29% $ (84 ) ___________________________________________ (a) Fair value is based on an estimate derived from option models. (b) Fair value is based on an estimate derived from industry standard methodologies which consider historical relationships among various commodities, modeled market prices, time value and volatility factors.

Oil and Natural Gas Property 48

Oil and Natural Gas Property Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
VPP Transactions	As of December 31, 2015 , our outstanding VPPs consisted of the following: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 10 March 2012 Anadarko Basin Granite Wash $ 744 3.0 87 9.2 160 9 May 2011 Mid-Continent 853 1.7 138 4.8 177 4 December 2008 Anadarko and Arkoma Basins 412 0.5 95 — 98 3 August 2008 Anadarko Basin 600 — 93 — 93 2 May 2008 Texas, Oklahoma and Kansas 622 — 94 — 94 1 December 2007 Kentucky and West Virginia 1,100 — 208 — 208 $ 4,331 5.2 715 14.0 830
VPP Volumes Produced During Period	The volumes produced on behalf of our VPP buyers during 2015, 2014 and 2013 were as follows: Year Ended December 31, 2015 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 310.0 8.5 1,043.9 16.6 9 167.9 14.2 375.9 17.4 8 (a) — 36.5 — 36.5 4 42.5 8.0 — 8.2 3 — 6.4 — 6.4 2 — 4.0 — 4.0 1 — 13.3 — 13.3 520.4 90.9 1,419.8 102.4 Year Ended December 31, 2014 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 403.0 10.6 1,296.5 20.7 9 187.5 15.4 411.0 19.0 8 — 60.1 — 60.1 6 (b) 23.1 4.2 — 4.3 5 (b) 16.5 4.6 — 4.7 4 48.1 9.0 — 9.2 3 — 7.2 — 7.2 2 — 6.2 — 6.2 1 — 13.8 — 13.8 678.2 131.1 1,707.5 145.2 Year Ended December 31, 2013 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 547.0 13.5 1,509.0 25.8 9 213.2 17.0 455.7 21.0 8 — 68.1 — 68.1 6 24.0 4.8 — 4.9 5 25.4 7.5 — 7.7 4 54.7 10.2 — 10.5 3 — 8.1 — 8.1 2 — 10.3 — 10.3 1 — 14.5 — 14.5 864.3 154.0 1,964.7 170.9 ____________________________________________ (a) VPP #8 expired in 2015. (b) We divested the properties associated with VPP #5 and VPP #6 in 2014.
VPP Volumes Remaining to Be Delivered	The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2015 were as follows: Volume Remaining as of December 31, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 74 1.0 29.6 3.6 57.4 9 62 0.7 59.0 1.6 72.4 4 12 — 7.3 — 7.6 3 43 — 17.5 — 17.5 2 40 — 9.8 — 9.8 1 84 — 78.3 — 78.3 1.7 201.5 5.2 243.0

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Investments [Abstract]
Equity Method Investments	A summary of our investments, including our approximate ownership percentage and carrying value as of December 31, 2015 and 2014, is presented below. Approximate Ownership % Carrying Value Accounting Method December 31, December 31, December 31, December 31, ($ in millions) Sundrop Fuels, Inc. Equity 56% 56% $ 119 $ 130 FTS International, Inc. Equity 30% 30% — 116 Other — —% —% 17 19 Total investments $ 136 $ 265

Other Property and Equipment (T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment, Summary of Other Property and Equipment	A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: December 31, Estimated Useful Life 2015 2014 ($ in millions) (in years) Buildings and improvements $ 1,209 $ 1,242 10 – 39 Natural gas compressors (a) 483 551 3 – 20 Land 289 296 Gathering systems and treating plants (a) 214 218 20 Other 732 776 2 – 20 Total other property and equipment, at cost 2,927 3,083 Less: accumulated depreciation $ (813 ) $ (804 ) Total other property and equipment, net $ 2,114 $ 2,279 ___________________________________________ (a) Included in our marketing, gathering and compression operating segment. A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Buildings and land $ 3 $ (2 ) $ 27 Natural gas compressors — (195 ) — Gathering systems and treating plants 1 8 (326 ) Oilfield services equipment — (7 ) 2 Other — (3 ) (5 ) Total net (gains) losses on sales of fixed assets $ 4 $ (199 ) $ (302 )
Property, Plant and Equipment, Net Gains of Sales of Fixed Assets	A summary of other property and equipment held for use and the estimated useful lives thereof is as follows: December 31, Estimated Useful Life 2015 2014 ($ in millions) (in years) Buildings and improvements $ 1,209 $ 1,242 10 – 39 Natural gas compressors (a) 483 551 3 – 20 Land 289 296 Gathering systems and treating plants (a) 214 218 20 Other 732 776 2 – 20 Total other property and equipment, at cost 2,927 3,083 Less: accumulated depreciation $ (813 ) $ (804 ) Total other property and equipment, net $ 2,114 $ 2,279 ___________________________________________ (a) Included in our marketing, gathering and compression operating segment. A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Buildings and land $ 3 $ (2 ) $ 27 Natural gas compressors — (195 ) — Gathering systems and treating plants 1 8 (326 ) Oilfield services equipment — (7 ) 2 Other — (3 ) (5 ) Total net (gains) losses on sales of fixed assets $ 4 $ (199 ) $ (302 )

Impairments (Tables)

Impairments (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Impairment Charges [Abstract]
Details of Impairment of Long-Lived Assets Held and Used by Asset	A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Natural gas compressors $ 21 $ 11 $ — Buildings and land — 18 366 Gathering systems and treating plants — 13 22 Oilfield services equipment — 23 71 Other 173 23 87 Total impairments of fixed assets and other $ 194 $ 88 $ 546

Restructuring Restructuring and

Restructuring Restructuring and Other Termination Costs (Tables)	12 Months Ended
	Dec. 31, 2015
Restructuring and Related Activities [Abstract]
Restructuring and Related Costs	A summary of our restructuring and other termination costs for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 ($ in millions) Restructuring charges under workforce reduction plan: Salary expense $ 47 $ — $ 20 Acceleration of stock-based compensation — — 45 Other termination benefits 8 — 1 Total restructuring changes under workforce reduction plan 55 — 66 Oilfield services spin-off costs: Transaction costs — 17 — Stock-based compensation adjustments for Chesapeake employees — 5 — Stock-based compensation forfeitures for SSE employees — (10 ) — Debt extinguishment costs — 3 — Total oilfield services spin-off costs — 15 — Termination benefits provided to Mr. McClendon: Salary and bonus expense — — 11 Acceleration of 2008 performance bonus clawback — — 11 Acceleration of stock-based compensation — — 22 Acceleration of performance share unit awards (a) (8 ) (8 ) 18 Estimated aircraft usage benefits — — 7 Total termination benefits provided to Mr. McClendon (8 ) (8 ) 69 Termination benefits provided to VSP participants: Salary and bonus expense — — 33 Acceleration of stock-based compensation — — 29 Other termination benefits — — 1 Total termination benefits provided to VSP participants — — 63 Other termination benefits (a) (11 ) — 50 Total restructuring and other termination costs $ 36 $ 7 $ 248 ____________________________________________ (a) Amounts for the years ended December 31, 2015 and 2014 are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 9.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Interest rate liabilities — — — — Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during 2015 and 2014 is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 100 316 Total purchases, issuances, sales and settlements: Settlements (137 ) (20 ) Ending balance as of December 31, 2015 $ (91 ) $ 297 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 292 1 Total purchases, issuances, sales and settlements: Settlements 136 — Transfers (b) (4 ) — Ending balance as of December 31, 2014 $ (54 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 100 $ 292 $ 296 $ 1 Change in unrealized gains (losses) related to assets still held at reporting date $ 43 $ 262 $ 296 $ — (b) The values related to basis swaps were transferred from Level 3 to Level 2 as a result of our ability to begin using data readily available in the public market to corroborate our estimated fair values. The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2015 and 2014: Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 )

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The components of the change in our asset retirement obligations are shown below. Years Ended December 31, 2015 2014 ($ in millions) Asset retirement obligations, beginning of period $ 465 $ 405 Additions 6 29 Revisions (a) 13 101 Settlements and disposals (34 ) (92 ) Accretion expense 23 22 Asset retirement obligations, end of period 473 465 Less current portion (b) 21 18 Asset retirement obligation, long-term $ 452 $ 447 _________________________________________ (a) Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settlement. (b) Balance is included in other current liabilities on the consolidated balance sheet.

Major Customers and Segment I55

Major Customers and Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Schedule of Segment Reporting Information, by Segment	The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2015 Revenues $ 5,391 $ 11,745 $ — $ — $ (4,372 ) $ 12,764 Intersegment revenues — (4,372 ) — — 4,372 — Total revenues $ 5,391 $ 7,373 $ — $ — $ — $ 12,764 Unrealized losses on commodity derivatives $ 693 $ — $ — $ — $ — $ 693 Unrealized gains on marketing derivatives $ — $ (295 ) $ — $ — $ — $ (295 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,170 $ 20 $ — $ 39 $ — $ 2,229 Impairment of oil and natural gas properties $ 18,238 $ — $ — $ — $ — $ 18,238 Impairments of fixed assets and other $ 126 $ 68 $ — $ — $ — $ 194 Net gain (loss) on sales of fixed assets $ 1 $ 1 $ — $ 2 $ — $ 4 Interest expense $ (925 ) $ (4 ) $ — $ 6 $ 606 $ (317 ) Losses on investments $ (3 ) $ — $ — $ (93 ) $ — $ (96 ) Impairments of investments $ — $ — $ — $ (53 ) $ — $ (53 ) Gains on purchases or exchanges of debt $ 279 $ — $ — $ — $ — $ 279 Income (Loss) Before Income Taxes $ (19,619 ) $ 117 $ — $ (127 ) $ 531 $ (19,098 ) Total Assets $ 11,819 $ 1,524 $ — $ 4,325 $ (311 ) $ 17,357 Capital Expenditures $ 3,562 $ 42 $ — $ 10 $ — $ 3,614 Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2014 Revenues $ 10,354 $ 20,790 $ 1,060 $ 30 $ (9,109 ) $ 23,125 Intersegment revenues — (8,565 ) (544 ) — 9,109 — Total revenues $ 10,354 $ 12,225 $ 516 $ 30 $ — $ 23,125 Unrealized gains on commodity derivatives $ (1,394 ) $ — $ — $ — $ — $ (1,394 ) Unrealized gains on marketing derivatives $ — $ (3 ) $ — $ — $ — $ (3 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,756 $ 38 $ 145 $ 42 $ (66 ) $ 2,915 Impairments of fixed assets and other $ 22 $ 24 $ 23 $ 19 $ — $ 88 Net gain (loss) on sales of fixed assets $ (2 ) $ (187 ) $ (8 ) $ (2 ) $ — $ (199 ) Interest expense $ (709 ) $ (21 ) $ (42 ) $ 3 $ 680 $ (89 ) Losses on investments $ 2 $ — $ (1 ) $ (76 ) $ — $ (75 ) Impairments of investments $ — $ — $ (5 ) $ — $ — $ (5 ) Net gain (loss) on sales of investments $ (6 ) $ — $ — $ 73 $ — $ 67 Losses on purchases or exchanges of debt $ (197 ) $ — $ — $ — $ — $ (197 ) Income (Loss) Before Income Taxes $ 2,874 $ 326 $ (16 ) $ (30 ) $ 46 $ 3,200 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751 Capital Expenditures $ 6,173 $ 298 $ 158 $ 38 $ — $ 6,667 Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Year Ended December 31, 2013 Revenues $ 8,626 $ 17,129 $ 2,188 $ 29 $ (8,892 ) $ 19,080 Intersegment revenues — (7,570 ) (1,309 ) (13 ) 8,892 — Total revenues $ 8,626 $ 9,559 $ 879 $ 16 $ — $ 19,080 Unrealized gains on commodity derivatives $ (228 ) $ — $ — $ — $ — $ (228 ) Oil, natural gas, NGL and other depreciation, depletion and amortization $ 2,674 $ 46 $ 289 $ 49 $ (155 ) $ 2,903 Impairments of fixed assets and other $ 27 $ 50 $ 75 $ 394 $ — $ 546 Net gain (loss) on sales of fixed assets $ 2 $ (329 ) $ (1 ) $ 26 $ — $ (302 ) Interest expense $ (918 ) $ (24 ) $ (82 ) $ (74 ) $ 871 $ (227 ) Losses on investments $ 3 $ — $ — $ (219 ) $ — $ (216 ) Impairments of investments $ — $ — $ (1 ) $ (10 ) $ 1 $ (10 ) Net gain (loss) on sales of investments $ — $ — $ — $ (7 ) $ — $ (7 ) Losses on purchases or exchanges of debt $ (193 ) $ — $ — $ — $ — $ (193 ) Income (Loss) Before Income Taxes $ 2,997 $ 511 $ (51 ) $ (727 ) $ (1,288 ) $ 1,442 Total Assets $ 35,341 $ 2,430 $ 2,018 $ 5,750 $ (3,757 ) $ 41,782 Capital Expenditures $ 6,198 $ 299 $ 272 $ 421 $ — $ 7,190

Condensed Consolidating Finan56

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Balance Sheet	CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 928 $ 2 $ 1 $ (106 ) $ 825 Other current assets 87 1,561 7 — 1,655 Intercompany receivable, net 24,789 — 434 (25,223 ) — Total Current Assets 25,804 1,563 442 (25,329 ) 2,480 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 11,861 69 159 12,089 Other property and equipment, net — 2,113 1 — 2,114 Property and equipment held for sale, net — 95 — — 95 Total Property and Equipment, Net — 14,069 70 159 14,298 LONG-TERM ASSETS: Other long-term assets 74 495 10 — 579 Investments in subsidiaries and intercompany advances (12,349 ) 771 — 11,578 — TOTAL ASSETS $ 13,529 $ 16,898 $ 522 $ (13,592 ) $ 17,357 CURRENT LIABILITIES: Current liabilities $ 921 $ 2,862 $ 8 $ (106 ) $ 3,685 Intercompany payable, net — 25,580 — (25,580 ) — Total Current Liabilities 921 28,442 8 (25,686 ) 3,685 LONG-TERM LIABILITIES: Long-term debt, net 10,354 — — — 10,354 Other long-term liabilities 116 805 — — 921 Total Long-Term Liabilities 10,470 805 — — 11,275 EQUITY: Chesapeake stockholders’ equity 2,138 (12,349 ) 514 11,835 2,138 Noncontrolling interests — — — 259 259 Total Equity 2,138 (12,349 ) 514 12,094 2,397 TOTAL LIABILITIES AND EQUITY $ 13,529 $ 16,898 $ 522 $ (13,592 ) $ 17,357 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 Restricted cash — — 38 — 38 Other current assets 55 3,174 93 — 3,322 Intercompany receivable, net 24,527 — 341 (24,868 ) — Total Current Assets 28,682 3,176 556 (24,946 ) 7,468 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 28,358 1,112 673 30,143 Other property and equipment, net — 2,276 3 — 2,279 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 30,727 1,115 673 32,515 LONG-TERM ASSETS: Other long-term assets 153 618 26 (29 ) 768 Investments in subsidiaries and intercompany advances 126 467 — (593 ) — TOTAL ASSETS $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CURRENT LIABILITIES: Current liabilities $ 761 $ 4,915 $ 58 $ (78 ) $ 5,656 Intercompany payable, net — 24,940 — (24,940 ) — Total Current Liabilities 761 29,855 58 (25,018 ) 5,656 LONG-TERM LIABILITIES: Long-term debt, net 11,154 — — — 11,154 Deferred income tax liabilities 31 3,917 244 200 4,392 Other long-term liabilities 112 1,090 142 — 1,344 Total Long-Term Liabilities 11,297 5,007 386 200 16,890 EQUITY: Chesapeake stockholders’ equity 16,903 126 1,253 (1,379 ) 16,903 Noncontrolling interests — — — 1,302 1,302 Total Equity 16,903 126 1,253 (77 ) 18,205 TOTAL LIABILITIES AND EQUITY $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751
Schedule of Condensed Income Statement	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 5,252 $ 139 $ — $ 5,391 Marketing, gathering and compression — 7,373 — — 7,373 Total Revenues — 12,625 139 — 12,764 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,019 27 — 1,046 Oil, natural gas and NGL gathering, processing and transportation — 2,094 25 — 2,119 Production taxes — 97 2 — 99 Marketing, gathering and compression — 7,129 1 — 7,130 General and administrative 1 231 3 — 235 Restructuring and other termination costs — 36 — — 36 Provision for legal contingencies 339 14 — — 353 Oil, natural gas and NGL depreciation, depletion and amortization — 2,051 69 (21 ) 2,099 Depreciation and amortization of other assets — 130 — — 130 Impairment of oil and natural gas properties — 18,224 472 (458 ) 18,238 Impairments of fixed assets and other — 194 — — 194 Net gains on sales of fixed assets — 4 — — 4 Total Operating Expenses 340 31,223 599 (479 ) 31,683 LOSS FROM OPERATIONS (340 ) (18,598 ) (460 ) 479 (18,919 ) OTHER INCOME (EXPENSE): Interest expense (721 ) (198 ) — 602 (317 ) Losses on investments — (96 ) — — (96 ) Impairments of investments — (53 ) — — (53 ) Gains on purchases or exchanges of debt 279 — — — 279 Other income (expense) 140 10 1 (143 ) 8 Equity in net earnings (losses) of subsidiary (14,197 ) (402 ) — 14,599 — Total Other Expense (14,499 ) (739 ) 1 15,058 (179 ) LOSS BEFORE INCOME TAXES (14,839 ) (19,337 ) (459 ) 15,537 (19,098 ) INCOME TAX EXPENSE (BENEFIT) (154 ) (4,421 ) (107 ) 219 (4,463 ) NET LOSS (14,685 ) (14,916 ) (352 ) 15,318 (14,635 ) Net income attributable to noncontrolling interests — — — (50 ) (50 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (14,685 ) (14,916 ) (352 ) 15,268 (14,685 ) Other comprehensive income 21 23 — — 44 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (14,664 ) $ (14,893 ) $ (352 ) $ 15,268 $ (14,641 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 9,899 $ 458 $ (3 ) $ 10,354 Marketing, gathering and compression — 12,220 5 — 12,225 Oilfield services — 41 983 (478 ) 546 Total Revenues — 22,160 1,446 (481 ) 23,125 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,166 42 — 1,208 Oil, natural gas and NGL gathering, processing and transportation — 2,134 40 — 2,174 Production taxes — 227 5 — 232 Marketing, gathering and compression — 12,232 4 — 12,236 Oilfield services — 53 769 (391 ) 431 General and administrative — 273 49 — 322 Restructuring and other termination costs — 4 3 — 7 Provision for legal contingencies 100 134 — — 234 Oil, natural gas and NGL depreciation, depletion and amortization — 2,523 162 (2 ) 2,683 Depreciation and amortization of other assets — 153 143 (64 ) 232 Impairment of oil and natural gas — — 349 (349 ) — Impairments of fixed assets and other — 65 23 — 88 Net gains on sales of fixed assets — (192 ) (7 ) — (199 ) Total Operating Expenses 100 18,772 1,582 (806 ) 19,648 INCOME (LOSS) FROM OPERATIONS (100 ) 3,388 (136 ) 325 3,477 OTHER INCOME (EXPENSE): Interest expense (657 ) (37 ) (42 ) 647 (89 ) Losses on investments — (77 ) — 2 (75 ) Impairments of investments — — (5 ) — (5 ) Net gain of sales of investments — 67 — — 67 Losses on purchases or exchanges of debt (195 ) (2 ) — — (197 ) Other income (expense) 502 198 (2 ) (676 ) 22 Equity in net earnings (losses) of subsidiary 2,206 (258 ) — (1,948 ) — Total Other Income (Expense) 1,856 (109 ) (49 ) (1,975 ) (277 ) INCOME (LOSS) BEFORE INCOME TAXES 1,756 3,279 (185 ) (1,650 ) 3,200 INCOME TAX EXPENSE (BENEFIT) (161 ) 1,264 (66 ) 107 1,144 NET INCOME (LOSS) 1,917 2,015 (119 ) (1,757 ) 2,056 Net income attributable to noncontrolling interests — — — (139 ) (139 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 1,917 2,015 (119 ) (1,896 ) 1,917 Other comprehensive income 1 18 — — 19 COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE $ 1,918 $ 2,033 $ (119 ) $ (1,896 ) $ 1,936 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS YEAR ENDED DECEMBER 31, 2013 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 8,013 $ 553 $ 60 $ 8,626 Marketing, gathering and compression — 9,547 12 — 9,559 Oilfield services — 221 1,836 (1,162 ) 895 Total Revenues — 17,781 2,401 (1,102 ) 19,080 OPERATING EXPENSES: Oil, natural gas and NGL production — 1,112 47 — 1,159 Oil, natural gas and NGL gathering, processing and transportation — 1,574 — — 1,574 Production taxes — 222 7 — 229 Marketing, gathering and compression — 9,455 6 — 9,461 Oilfield services — 239 1,434 (937 ) 736 General and administrative — 375 83 (1 ) 457 Restructuring and other termination costs — 244 4 — 248 Oil, natural gas and NGL depreciation, depletion and amortization — 2,336 253 — 2,589 Depreciation and amortization of other assets — 180 281 (147 ) 314 Impairment of oil and natural gas — (2 ) 313 (311 ) — Impairments of fixed assets and other — 417 129 — 546 Net gains on sales of fixed assets — (301 ) (1 ) — (302 ) Total Operating Expenses — 15,851 2,556 (1,396 ) 17,011 INCOME (LOSS) FROM OPERATIONS — 1,930 (155 ) 294 2,069 OTHER INCOME (EXPENSE): Interest expense (921 ) (4 ) (85 ) 783 (227 ) Losses on investments — (216 ) — — (216 ) Impairments of investments — (9 ) (1 ) — (10 ) Net loss on sales of investments — (7 ) — — (7 ) Losses on purchases or exchanges of debt (70 ) (123 ) — — (193 ) Other income (expense) 3,979 (603 ) 13 (3,363 ) 26 Equity in net earnings (losses) of subsidiary (1,129 ) (383 ) — 1,512 — Total Other Income (Expense) 1,859 (1,345 ) (73 ) (1,068 ) (627 ) INCOME (LOSS) BEFORE INCOME TAXES 1,859 585 (228 ) (774 ) 1,442 INCOME TAX EXPENSE (BENEFIT) 1,135 369 (87 ) (869 ) 548 NET INCOME (LOSS) 724 216 (141 ) 95 894 Net income attributable to noncontrolling interests — — — (170 ) (170 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 724 216 (141 ) (75 ) 724 Other comprehensive income (loss) 3 19 (2 ) — 20 COMPREHENSIVE INCOME (LOSS) $ 727 $ 235 $ (143 ) $ (75 ) $ 744
Schedule of Condensed Cash Flow Statement	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 1,142 $ 110 $ (18 ) $ 1,234 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (3,032 ) (63 ) — (3,095 ) Acquisitions of proved and unproved properties — (529 ) (4 ) — (533 ) Proceeds from divestitures of proved and unproved properties — 152 37 — 189 Additions to other property and equipment — (148 ) 5 — (143 ) Other investing activities — 67 52 12 131 Net Cash Used In Investing Activities — (3,490 ) 27 12 (3,451 ) CASH FLOWS FROM FINANCING ACTIVITIES: Cash paid to repurchase noncontrolling interest of CHK C-T — — (143 ) — (143 ) Cash paid to purchase debt (508 ) — — — (508 ) Other financing activities (789 ) 473 (77 ) (22 ) (415 ) Intercompany advances, net (1,875 ) 1,875 — — — Net Cash Provided by (Used In) Financing Activities (3,172 ) 2,348 (220 ) (22 ) (1,066 ) Net decrease in cash and cash equivalents (3,172 ) — (83 ) (28 ) (3,283 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 928 $ 2 $ 1 $ (106 ) $ 825 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 4,201 $ 462 $ (29 ) $ 4,634 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (4,445 ) (136 ) — (4,581 ) Acquisitions of proved and unproved properties — (1,306 ) (5 ) — (1,311 ) Proceeds from divestitures of proved and unproved properties — 5,812 1 — 5,813 Additions to other property and equipment — (480 ) (246 ) — (726 ) Other investing activities — 1,199 60 — 1,259 Net Cash Provided By (Used In) Investing Activities — 780 (326 ) — 454 CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 6,689 717 — 7,406 Payments on credit facilities borrowings — (6,689 ) (1,099 ) — (7,788 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,966 — 494 — 3,460 Proceeds from issuance of oilfield services term loan, net of issuance costs — — 394 — 394 Cash paid to purchase debt (3,362 ) — — — (3,362 ) Other financing activities (439 ) (1,278 ) (169 ) (41 ) (1,927 ) Intercompany advances, net 4,136 (3,709 ) (427 ) — — Net Cash Provided By (Used In) Financing Activities 3,301 (4,987 ) (90 ) (41 ) (1,817 ) Net increase (decrease) in cash and cash equivalents 3,301 (6 ) 46 (70 ) 3,271 Cash and cash equivalents, beginning of period 799 8 38 (8 ) 837 Cash and cash equivalents, end of period $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS YEAR ENDED DECEMBER 31, 2013 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 4,218 $ 439 $ (43 ) $ 4,614 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (4,838 ) (766 ) — (5,604 ) Acquisitions of proved and unproved properties — (1,378 ) 346 — (1,032 ) Proceeds from divestitures of proved and unproved properties — 3,466 1 — 3,467 Additions to other property and equipment — (271 ) (701 ) — (972 ) Other investing activities — 246 765 163 1,174 Net Cash Used In Investing Activities — (2,775 ) (355 ) 163 (2,967 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 6,452 1,217 — 7,669 Payments on credit facilities borrowings — (6,452 ) (1,230 ) — (7,682 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,274 — — — 2,274 Cash paid to purchase debt (2,141 ) — — — (2,141 ) Proceeds from sales of noncontrolling interests — — 6 — 6 Other financing activities 1,819 (2,897 ) (17 ) (128 ) (1,223 ) Intercompany advances, net (1,381 ) 1,462 (81 ) — — Net Cash Provided By (Used In) Financing Activities 571 (1,435 ) (105 ) (128 ) (1,097 ) Net increase (decrease) in cash and cash equivalents 571 8 (21 ) (8 ) 550 Cash and cash equivalents, beginning of period 228 — 59 — 287 Cash and cash equivalents, end of period $ 799 $ 8 $ 38 $ (8 ) $ 837

Basis of Presentation and Sum57

Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Summary of Significant Accounting Policies - Receivables Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$ 226	$ 226
Oil and Gas Joint Interest Billing Receivables, Current	230	691
Allowance for Doubtful Accounts Receivable	(23)	(21)
Accounts receivable, net	1,129	2,236
Oil And Gas Exploration And Production [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Other Receivables	$ 696	$ 1,340

Basis of Presentation and Sum58

Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Summary of Significant Accounting Policies - Capitalized Costs Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accounting Policies [Abstract]
Acquisition Costs, Period Cost	$ 121	$ 651	$ 200	$ 4,304
Acquisition Costs, Cumulative	5,276
Exploration Costs, Period Cost	68	13	15	58
Exploration Costs, Cumulative	154
Capitalized Interest of Unproved Properties Excluded from Amortization	331	303	259	475
Capitalized Interest Of Unproved Properties Excluded From Amortization Cumulative	1,368
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	520	967	$ 474	$ 4,837
Capitalized Costs of Unproved Properties, Excluded from Amortization, Cumulative	$ 6,798	$ 9,788

Basis of Presentation and Sum59

Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Summary of Significant Accounting Policies Oil, Natural Gas and NGL Sales Revenue Restatement Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL	$ 5,391	$ 10,354	$ 8,626
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL		8,180	7,052
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL		$ 2,174	$ 1,574

Basis of Presentation and Sum60

Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Significant Accounting Policies Oil, Natural Gas and NGL Transportation and Other Expenses Restated Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL gathering, processing and transportation	$ 2,119	$ 2,174	$ 1,574
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL gathering, processing and transportation		0	0
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Oil, natural gas and NGL gathering, processing and transportation		$ 2,174	$ 1,574

Basis of Presentation and Sum61

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions

Feb. 22, 2016

Feb. 09, 2016

Dec. 01, 2015

Sep. 29, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Feb. 24, 2016

Sep. 30, 2015

Apr. 24, 2014

Dec. 31, 2012

Summary of Significant Accounting Policies [Table] [Line Items]

Impairment of oil and natural gas properties

$ 18,238

$ 0

$ 0

NET INCOME (LOSS)

(14,635)

2,056

894

Cash and cash equivalents

825

4,108

837

$ 287

Working Capital (Deficit)

(1,205)

Debt Instrument, Face Amount

9,706

11,756

Payments to Acquire Productive Assets

3,600

6,667

7,190

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

381

Long-term Debt, Maturities, Repayments of Principal in Year Two

1,892

Long-term Debt, Maturities, Repayments of Principal in Year Three

$ 878

Restructuring, Percentage of Employees Effected

15.00%

Noncontrolling Interest, Ownership Percentage by Parent

50.00%

Provision for Doubtful Accounts

$ 4

2

2

Percentage of Reserve Estimates (by Volume) Prepared by Independent Engineering Firm

59.00%

Bank Overdrafts

$ 60

333

Unamortized Debt Issuance Expense

74

130

Gas Balancing Asset (Liability)

$ (10)

(12)

Percentage of Reserve Estimates (by Value) Prepared by Independent Engineering Firm

77.00%

Director [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period

3 years

3.25% Senior Notes due 2016 [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

3.25%

Senior Notes [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Face Amount

3,000

2,300

$ 3,000

Noncontrolling Interest, Ownership Percentage by Parent

100.00%

Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Face Amount

$ 329

416

Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Face Amount

$ 381

500

$ 500

Debt Instrument, Interest Rate, Stated Percentage

3.25%

3.25%

Debt Instrument, Repurchased Face Amount

$ 119

Senior Notes [Member] | Existing Notes [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Repurchased Face Amount

3,929

Senior Notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Face Amount

$ 2,425

$ 0

Debt Instrument, Interest Rate, Stated Percentage

8.00%

8.00%

Revolving Credit Facility [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Line of Credit Facility, Fair Value of Amount Outstanding

$ 0

Borrowing capacity

$ 4,000

Subsequent Event [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Collateral Posted

$ 92

Line of Credit Facility, Collateral

We have posted the required collateral, primarily in the form of letters of credit and cash, or are otherwise complying with these contractual requests for collateral.

Subsequent Event [Member] | Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Interest Rate, Stated Percentage

3.25%

Debt Instrument, Repurchased Face Amount

$ 122

Subsequent Event [Member] | Revolving Credit Facility [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Cash Collateral for Borrowed Securities

$ 220

Standard & Poor's, BB- Rating [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Credit Rating

BB-

Standard & Poor's, CC Rating [Member] | Subsequent Event [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Credit Rating

CC

Moody's, Ba3 Rating [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Credit Rating

Ba3

Moody's, Caa3 Rating [Member] | Subsequent Event [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Debt Instrument, Credit Rating

“Caa3

Minimum [Member] | Employee [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period

3 years

Maximum [Member] | Employee [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period

4 years

Scenario, Forecast [Member] | Subsequent Event [Member] | Revolving Credit Facility [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Cash Collateral for Borrowed Securities

$ 698

Scenario, Forecast [Member] | Minimum [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Payments to Acquire Productive Assets

1,300

Scenario, Forecast [Member] | Maximum [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Payments to Acquire Productive Assets

$ 1,800

Restatement Adjustment [Member]

Summary of Significant Accounting Policies [Table] [Line Items]

Deferred income tax liabilities

$ 207

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 0	$ 26	$ 10
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1	3	5
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 86		$ 86
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	59		56
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 63		$ 63
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	42		40
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 10		$ 10
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6		5
4.50% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 12		$ 12
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6		6

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share - Reconciliation of Basic and Diluted EPS Table (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (14,856)	$ 1,273	$ 474
Weighted Average Number of Shares Outstanding, Basic	662	659	653
Earnings Per Share, Basic	$ (22.43)	$ 1.93	$ 0.73
Net Income (Loss) Available to Common Stockholders, Diluted		$ 1,444
Weighted Average Number of Shares Outstanding, Diluted	662	772	653
Earnings Per Share, Diluted	$ (22.43)	$ 1.87	$ 0.73
5.75% Cumulative Convertible Preferred Stock [Member] | Convertible Debt Securities [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities		$ 86
Weighted Average Number Diluted Shares Outstanding Adjustment		59
5.75% Cumulative Convertible Preferred Stock Series A [Member] | Convertible Debt Securities [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities		$ 63
Weighted Average Number Diluted Shares Outstanding Adjustment		42
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member] | Convertible Debt Securities [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities		$ 10
Weighted Average Number Diluted Shares Outstanding Adjustment		6
4.50% Cumulative Convertible Preferred Stock [Member] | Convertible Debt Securities [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities		$ 12
Weighted Average Number Diluted Shares Outstanding Adjustment		6

Debt - Long-Term Debt Table (De

Debt - Long-Term Debt Table (Details) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / shares$ / €	Dec. 31, 2014USD ($)$ / €	Apr. 24, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2006$ / €
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 9,706	$ 11,756
Long-term Debt, Gross	10,735	11,535
Long-term debt, net	$ 10,354	11,154
Commitment Period	10 years
Current maturities of long-term debt, net	$ (381)	(381)
Long-term debt, current maturities including discount	(381)	(396)
Long-term Debt, Fair Value	9,325	11,360
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	0
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount		3,000	$ 3,000	$ 2,300
Debt Instrument, Unamortized Discount	(133)	(224)
Line of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	0	0
Long-term Debt, Gross	$ 0	0
Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Percentage Of Principal Amount Of Notes For Repurchase Requirement Of Contingent Convertible Senior Notes	100.00%
Commitment Period	10 years
Debt Instrument, Redemption Price, Percentage	100.00%
Debt Instrument, Convertible, Terms of Conversion Feature	5 days
Debt Instrument, Redemption, Period One [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	5 years
Debt Instrument, Redemption, Period Two [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	10 years
Debt Instrument, Redemption, Period Three [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	15 years
Debt Instrument, Redemption, Period Four [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	20 years
Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 0	0
Long-term Debt, Gross	$ 7	10
3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 381	500		$ 500
Long-term Debt, Gross	381	500
Debt Instrument, Unamortized Discount	$ (15)
Debt Instrument, Interest Rate, Stated Percentage	3.25%			3.25%
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 329	416
Long-term Debt, Gross	$ 329	$ 416
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Cross Currency Interest Rate Contract [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Derivative, Forward Exchange Rate | $ / €	1.0862	1.2098			1.3325
Debt Instrument, Interest Rate, Stated Percentage	6.25%
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 453	$ 660
Long-term Debt, Gross	$ 452	659
Debt Instrument, Interest Rate, Stated Percentage	6.50%
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 538	669
Long-term Debt, Gross	$ 538	669
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,104	1,500
Long-term Debt, Gross	1,104	1,500
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	822	1,300
Long-term Debt, Gross	$ 822	1,300
Debt Instrument, Interest Rate, Stated Percentage	6.625%
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 304	500
Long-term Debt, Gross	$ 303	497
Debt Instrument, Interest Rate, Stated Percentage	6.875%
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 589	1,000
Long-term Debt, Gross	$ 589	1,000
Debt Instrument, Interest Rate, Stated Percentage	6.125%
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 286	700		$ 700
Long-term Debt, Gross	$ 286	700
Debt Instrument, Interest Rate, Stated Percentage	5.375%			5.375%
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 639	1,500
Long-term Debt, Gross	$ 639	$ 1,500
Debt Instrument, Interest Rate, Stated Percentage	4.875%	4.875%
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 2,425	$ 0
Long-term Debt, Gross	$ 3,584	$ 0
Debt Instrument, Interest Rate, Stated Percentage	8.00%	8.00%
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 384	$ 1,100		$ 1,100
Long-term Debt, Gross	$ 384	1,100
Debt Instrument, Interest Rate, Stated Percentage	5.75%			5.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds | $ / shares	$ 45.02
Debt Instrument, Date of First Required Payment	May 14, 2016
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 2	396
Long-term Debt, Gross	$ 2	381
Debt Instrument, Interest Rate, Stated Percentage	2.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds | $ / shares	$ 59.44
Debt Instrument, Date of First Required Payment	Nov. 14, 2017
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,110	1,168
Long-term Debt, Gross	$ 1,026	1,024
Debt Instrument, Interest Rate, Stated Percentage	2.50%
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds | $ / shares	$ 100.20
Debt Instrument, Date of First Required Payment	Jun. 14, 2019
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 340	347
Long-term Debt, Gross	$ 289	$ 279
Debt Instrument, Interest Rate, Stated Percentage	2.25%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%

Debt - Long Term Debt Table (Ph

Debt - Long Term Debt Table (Phantom) (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%		3.25%
Debt Instrument Maturity Date	Mar. 15, 2016
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debt Instrument Maturity Date	Jan. 15, 2017
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Date	Aug. 15, 2017
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Date	Dec. 15, 2018
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	Apr. 15, 2019
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Debt Instrument Maturity Date	Aug. 15, 2020
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Debt Instrument Maturity Date	Nov. 15, 2020
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument Maturity Date	Feb. 15, 2021
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.375%		5.375%
Debt Instrument Maturity Date	Jun. 15, 2021
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%	4.875%
Debt Instrument Maturity Date	Apr. 15, 2022
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.00%	8.00%
Debt Instrument Maturity Date	Dec. 5, 2022
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.75%		5.75%
Debt Instrument Maturity Date	Mar. 15, 2023
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	November 15, 2015, 2020, 2025, 2030
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument Maturity Date	Nov. 15, 2035
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	May 15, 2017, 2022, 2027, 2032
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument Maturity Date	May 17, 2037
2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instruments Convertible Optional Repurchase Dates	December 15, 2018, 2023, 2028, 2033
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument Maturity Date	Dec. 15, 2038

Debt Debt - Schedule of Maturit

Debt Debt - Schedule of Maturities of Long-Term Debt Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 381
Long-term Debt, Maturities, Repayments of Principal in Year Two	1,892
Long-term Debt, Maturities, Repayments of Principal in Year Three	878
Long-term Debt, Maturities, Repayments of Principal in Year Four	1,104
Long-term Debt, Maturities, Repayments of Principal in Year Five	1,128
Long-term Debt, Maturities, Repayments of Principal after Year Five	4,323
Debt Instrument, Face Amount	$ 9,706	$ 11,756

Debt - Senior Secured Second Li

Debt - Senior Secured Second Lien Notes Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11,535		$ 10,735
Debt Instrument, Face Amount	11,756		$ 9,706
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		$ 37
Debt Instrument, Face Amount	3,000	$ 2,300		$ 3,000
Payments of Financing Costs	$ (30)
Senior Notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.00%		8.00%
Long-term Debt, Gross	$ 0		$ 3,584
Debt Instrument, Face Amount	0		2,425
Senior Notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior Note Exhange [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross			2,219
Senior Notes [Member] | Existing Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			3,929
Senior Notes [Member] | 10 of the 12 Existing Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross			3,679
Gain (Loss) on Repurchase of Debt Instrument	$ 304
Debt Instrument, Face Amount			$ 1,159

Debt - Senior Notes and Conting

Debt - Senior Notes and Contingent Convertible Senior Notes Narrative (Details) - USD ($) $ in Millions	Jul. 17, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 24, 2016	Dec. 31, 2015	Nov. 16, 2015	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent					50.00%
Long-term Debt, Gross		$ 11,535			$ 10,735
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Debt Instrument, Face Amount		11,756			$ 9,706
3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					3.25%
Gain (Loss) on Repurchase of Debt Instrument		5
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent					100.00%
Debt Instrument, Repurchase Amount			$ 405
Proceeds from issuance of senior notes, net of discount and offering costs		2,966	2,274
Gain (Loss) on Repurchase of Debt Instrument			37
Debt Instrument, Face Amount		3,000	2,300				$ 3,000
Senior Notes [Member] | Premium on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument			32
Senior Notes [Member] | Unamortized Deferred Charges on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument			$ 5
Senior Notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 0			$ 3,584
Debt Instrument, Interest Rate, Stated Percentage		8.00%			8.00%
Debt Instrument, Face Amount		$ 0			$ 2,425
Senior Notes [Member] | Existing Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount					3,929
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		1,024			$ 1,026
Debt Instrument, Interest Rate, Stated Percentage					2.50%
Debt Instrument, Face Amount		1,168			$ 1,110
Senior Notes [Member] | 2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		381			$ 2
Debt Instrument, Interest Rate, Stated Percentage					2.75%
Debt Instrument, Face Amount		396			$ 2
Senior Notes [Member] | 2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		279			$ 289
Debt Instrument, Interest Rate, Stated Percentage					2.25%
Debt Instrument, Face Amount		347			$ 340
Senior Notes [Member] | 10 of the 12 Existing Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross					3,679
Gain (Loss) on Repurchase of Debt Instrument		304
Debt Instrument, Face Amount					1,159
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		416			329
Debt Instrument, Face Amount		416			329
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		659			$ 452
Debt Instrument, Interest Rate, Stated Percentage					6.50%
Debt Instrument, Face Amount		660			$ 453
Senior Notes [Member] | 6.775% Senior Notes Due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.775%
Loss Contingency, Damages Awarded, Value	$ 380
Loss Contingency, Prejudgment Interest Awarded	$ 59
Debt Instrument, Repurchased Face Amount			$ 1,300
Gain (Loss) on Repurchase of Debt Instrument			33
Senior Notes [Member] | 6.775% Senior Notes Due 2019 [Member] | Unamortized Discount on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument			14
Senior Notes [Member] | 6.775% Senior Notes Due 2019 [Member] | Unamortized Deferred Charges on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument			$ 19
Senior Notes [Member] | Floating Rate Senior Notes due 2019 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		1,500			1,104
Debt Instrument, Face Amount		1,500			1,104
Senior Notes [Member] | 4.875% Senior Notes due 2022 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,500			$ 639
Debt Instrument, Interest Rate, Stated Percentage		4.875%			4.875%
Debt Instrument, Face Amount		$ 1,500			$ 639
Senior Notes [Member] | 6.875% Senior Notes due 2018 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.875%	6.875%
Debt Instrument, Repurchased Face Amount		$ 97	$ 377
Gain (Loss) on Repurchase of Debt Instrument		6
Senior Notes [Member] | 6.875% Senior Notes due 2018 [Member] | Premium on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		5
Senior Notes [Member] | 6.875% Senior Notes due 2018 [Member] | Unamortized Deferred Charges on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		$ 1
Senior Notes [Member] | 9.5% Senior Notes due 2015 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.50%
Debt Instrument, Repurchased Face Amount		$ 1,265	$ 1,454
Gain (Loss) on Repurchase of Debt Instrument		99
Senior Notes [Member] | 9.5% Senior Notes due 2015 [Member] | Premium on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		87
Senior Notes [Member] | 9.5% Senior Notes due 2015 [Member] | Unamortized Discount on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		9
Senior Notes [Member] | 9.5% Senior Notes due 2015 [Member] | Unamortized Deferred Charges on Extinguishment of Debt [Member]
Long-Term Debt Instrument [Line Items]
Gain (Loss) on Repurchase of Debt Instrument		3
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		500			$ 381
Debt Instrument, Interest Rate, Stated Percentage			3.25%		3.25%
Debt Instrument, Repurchased Face Amount					$ 119
Debt Instrument, Face Amount		500	$ 500		381
Senior Notes [Member] | 5.375% Senior Notes due 2021 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		700			$ 286
Debt Instrument, Interest Rate, Stated Percentage			5.375%		5.375%
Debt Instrument, Face Amount		700	$ 700		$ 286
Senior Notes [Member] | 7.625% Senior Notes due 2013 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7.625%
Debt Instrument, Repurchase Amount			$ 221
Debt Instrument, Repurchased Face Amount			$ 217
Senior Notes [Member] | 5.75% Senior Notes due 2023 [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		1,100			$ 384
Debt Instrument, Interest Rate, Stated Percentage			5.75%		5.75%
Debt Instrument, Face Amount		$ 1,100	$ 1,100		$ 384
Senior Notes [Member] | Subsequent Event [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				6.50%
Debt Instrument, Repurchase Amount				$ 1
Debt Instrument, Repurchased Face Amount				$ 2
Senior Notes [Member] | Subsequent Event [Member] | 3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.25%
Debt Instrument, Repurchase Amount				$ 115
Debt Instrument, Repurchased Face Amount				$ 122
Senior Notes [Member] | 3rd Quarter 2013 [Member] | 7.625% Senior Notes due 2013 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			$ 247
Convertible Debt [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount					50
Convertible Debt [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount					$ 75
Convertible Debt [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					2.50%
Debt Instrument, Interest Rate, Effective Percentage					8.00%
Convertible Debt [Member] | 2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					2.75%
Debt Instrument, Interest Rate, Effective Percentage					6.86%
Debt Instrument, Repurchased Face Amount						$ 394
Convertible Debt [Member] | 2.25% Contingent Convertible Senior Notes Due 2038 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage					2.25%
Debt Instrument, Interest Rate, Effective Percentage					8.00%
Convertible Debt [Member] | Subsequent Event [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				2.50%
Debt Instrument, Repurchase Amount				$ 32
Debt Instrument, Repurchased Face Amount				$ 60

Debt - Revolving Credit Facilit

Debt - Revolving Credit Facility Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2017	Sep. 30, 2015	Apr. 24, 2014
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount			$ 9,706	$ 11,756
Interest expense on senior notes			$ 682	704	$ 740
Line of Credit Facility, Borrowing Capacity, Description			The amended credit facility provides that, while the obligations are required to be secured, (i) we have the right to incur junior lien indebtedness of up to $4.0 billion; (ii) our use of the facility will be subject to a borrowing base; (iii) the rate of interest on outstanding loans, as well as fees on undrawn commitments, will vary based on the percentage of the borrowing base used, rather than on our credit ratings; (iv) the total leverage ratio covenant will be suspended; and (v) the credit facility will be subject to a first lien secured leverage ratio and an interest rate coverage ratio (as described below). The permitted junior lien debt basket of $4.0 billion may be increased upon the satisfaction of certain conditions, including the following: (i) after giving effect to all debt secured by such junior liens and the uses of such debt in retirement of other indebtedness, our net annual cash interest expense would increase by no more than $75 million, and (ii) we have exchanged debt secured by such junior liens for more than $2.0 billion aggregate principal amount of outstanding senior notes with maturities or initial put dates in 2017 through 2019. The September amendment sets the borrowing base at $4.0 billion. The total commitments under the credit facility remain at $4.0 billion, subject to reduction in connection with issuances of junior lien indebtedness by us after April 15, 2016, the date of the first borrowing base redetermination. No adjustment to the total commitment has occurred or will occur for any junior lien indebtedness issuance that occurs before April 15, 2016.
Long-term Debt, Gross			$ 10,735	11,535
Line of Credit Facility, Covenant Terms			a requirement that we maintain, as of the last day of each fiscal quarter, a net debt to capitalization ratio (as defined in the amended credit agreement) that does not exceed 65%. While it is required to be secured by a portion of our oil and natural gas properties, the amended credit facility requires us to maintain, as of the last day of each fiscal quarter (i) a first lien secured leverage ratio (as defined in the amended credit agreement) of 3.5 to 1.0 through 2017 and no more than 3.0 to 1.0 thereafter, and (ii) an interest rate coverage ratio (as defined in the amended credit agreement) of at least 1.1 to 1.0 through the first quarter of 2017, increasing to 1.25 to 1.0 by the end of 2017.
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity							$ 4,000
Long-term Debt, Gross			$ 0
Letters of Credit Outstanding, Amount			$ 16
Interest Rate In Addition To Federal Funds Rate			0.50%
Loans Receivable, Basis Spread on Variable Rate			1.00%
Line of Credit Facility, Guarantee Event One			cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more
Line of Credit Facility, Guarantee Event Two			bankruptcy; judgments involving liability of $125 million or more that are not paid
Line of Credit Facility, Guarantee Event Three			ERISA events
Credit Facility Default Value, Cross Payment Default and Cross Acceleration With Respect to Indebtedness Aggregate Minimum Principal Amount			$ 125
Credit Facility Default Value, Bankruptcy - Judgments Involving Liability, Minimum Principal Amount			$ 125
Revolving Credit Facility [Member] | Alternative Base Rate (ABR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			1.00%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End			2.00%
Revolving Credit Facility [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital			0.65
Revolving Credit Facility [Member] | Junior Lien [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity			$ 4,000
Revolving Credit Facility [Member] | Junior Lien [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity			2,000
Revolving Credit Facility [Member] | Junior Lien [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Interest Revenue (Expense), Net			75
Interest expense on senior notes			75
Revolving Credit Facility [Member] | First Lien Secured Leverage Ratio [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Covenant Description		3.0 to 1				3.5 to 1
Revolving Credit Facility [Member] | Interest Rate Coverage Ratio [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Covenant Description	1.25 to 1.0					1.1 to 1.0
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 3,000	$ 2,300			$ 3,000
Senior Notes [Member] | Revolving Credit Facility [Member] | Junior Lien [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount			2,000
Convertible Debt [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount			50
Convertible Debt [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount			75
Convertible Debt [Member] | Revolving Credit Facility [Member] | Junior Lien [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount			$ 2,000

Debt Debt - Term Loan (Details)

Debt Debt - Term Loan (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Apr. 24, 2014	Nov. 07, 2012
Long-Term Debt Instrument [Line Items]
Commitment Period		10 years
Debt Instrument, Face Amount		$ 9,706	$ 11,756
Gains (Losses) on Extinguishment of Debt		$ 304	(63)	$ (40)
Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	5 years
Debt Instrument, Face Amount						$ 2,000
Proceeds from Issuance of Unsecured Debt	$ 1,935
Gains (Losses) on Extinguishment of Debt			90
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount			3,000	$ 2,300	$ 3,000
Unamortized Discount on Extinguishment of Debt [Member] | Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt			30
Premium on Extinguishment of Debt [Member] | Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt			40
Unamortized Deferred Charges on Extinguishment of Debt [Member] | Unsecured Debt [Member]
Long-Term Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt			$ 20

Debt Debt - Spin-Off of Oilfiel

Debt Debt - Spin-Off of Oilfield Services Business (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2014	Apr. 24, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period	10 years
Long-term Debt, Gross	$ 10,735		$ 11,535
Debt Instrument, Face Amount	$ 9,706		11,756
Proceeds from issuance of senior notes, net of discount and offering costs			3,460
Senior Notes [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Payments of Financing Costs			(30)
Debt Instrument, Face Amount			3,000	$ 2,300		$ 3,000
Proceeds from issuance of senior notes, net of discount and offering costs			$ 2,966	$ 2,274
Seven Seven Energy Inc. [Member] | Seven Seven Energy Inc. Revolving Credit Facility [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity					$ 275
Seven Seven Energy Inc. [Member] | Secured Debt [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross					400
Seven Seven Energy Inc. [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2022 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross					$ 500
Debt Instrument, Interest Rate, Stated Percentage					6.50%
General Partner Distributions		$ 391
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | Seven Seven Energy Inc. [Member] | Seven Seven Energy Inc. Revolving Credit Facility [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period		5 years
Borrowing capacity					$ 275
Payments of Financing Costs		$ 3
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | Seven Seven Energy Inc. [Member] | Secured Debt [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period		7 years
Long-term Debt, Gross					400
Proceeds from Issuance of Secured Debt		$ 394
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | Seven Seven Energy Inc. [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2022 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Debt Instrument, Face Amount					$ 500
Debt Instrument, Interest Rate, Stated Percentage					6.50%
Proceeds from issuance of senior notes, net of discount and offering costs		494
General Partner Distributions		$ 391

Debt - Fair Value of Other Fina

Debt - Fair Value of Other Financial Instruments (Table) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 9,325	$ 11,360
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	381	381
Long-term Debt, Fair Value	10,347	11,144
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	366	396
Long-term Debt, Fair Value	$ 3,735	$ 11,656

Contingencies - Narrative (Deta

Contingencies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Loss Contingencies [Line Items]
Provision for legal contingencies	$ 353	$ 234	$ 0
Redemption of 2019 Notes [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies	$ 339	$ 100

Contingencies and Commitments C

Contingencies and Commitments Commitments - Undiscounted Operating Leases Table (Details) $ in Millions	Dec. 31, 2015USD ($)
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 4
Operating Leases, Future Minimum Payments, Due in Two Years	2
Operating Leases, Future Minimum Payments, Due in Three Years	2
Operating Leases, Future Minimum Payments, Due in Four Years	1
Operating Leases, Future Minimum Payments Due	$ 9

Commitments - Undiscounted Gath

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) - Gathering and Processing Equipment [Member] $ in Millions	Dec. 31, 2015USD ($)
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Remainder of Year	$ 1,932
Gathering, Processing and Transportation Commitment, Due in Second Year	1,944
Gathering, Processing and Transportation Commitment, Due in Third Year	1,742
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,443
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,111
Gathering, Processing and Transportation Commitment, Due after Fifth Year	5,793
Gathering, Processing and Transportation Commitment	$ 13,965

Contingencies and Commitments76

Contingencies and Commitments Commitments - Undiscounted Drilling Contracts Table (Details) - Drilling Rig Leases [Member] $ in Millions	Dec. 31, 2015USD ($)
Drilling Contracts [Line Items]
Drilling Contracts Obligation, Due in Next Fiscal Year	$ 160
Drilling Contracts Obligation, Due in Second Year	114
Drilling Contracts Obligation, Due in Third Year	6
Drilling Contracts Total Obligation	$ 280

Contingencies and Commitments77

Contingencies and Commitments Commitments - Undiscounted Pressure Pumping Contracts Table (Details) $ in Millions	Dec. 31, 2015USD ($)
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	$ 4
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	2
Pressure Pumping Contracts Total Future Minimum Payments Due	9
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Other Commitments [Line Items]
Pressure Pumping Contracts, Future Minimum Payments Due, Next Twelve Months	122
Pressure Pumping Contracts, Future Minimum Payments, Due in Two Years	64
Pressure Pumping Contracts Total Future Minimum Payments Due	$ 186

Commitments - Narrative (Detail

Commitments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Crew	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Long-term Purchase Commitment [Line Items]
Operating Leases, Rent Expense | $	$ 7	$ 33	$ 158
Gathering Fee Escalation Rate	15.00%
Provision for legal contingencies | $	$ 340	$ 234	$ 0
Net Acreage Shortfall [Member] | Total [Member]
Long-term Purchase Commitment [Line Items]
Provision for legal contingencies | $	$ 70
Drilling Rig Leases [Member] | Minimum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Minimum [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 months
Drilling Rig Leases [Member] | Maximum [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Drilling Rig Leases [Member] | Maximum [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Lease Term	3 years
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Percent of Total	50.00%
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year One of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	7
Year of Service Agreement	1 year
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year Two of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	5
Year of Service Agreement	2 years
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year Three of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	3
Year of Service Agreement	3 years

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Other Current Liabilities [Line Items]
Revenues and royalties due others	$ 500	$ 1,176
Accrued drilling and production costs	212	385
Joint interest prepayments received	169	189
Accrued compensation and benefits	264	344
Other accrued taxes	21	55
Accrued dividends	0	101
Minimum gathering volume commitment	201	141
Other current liabilities	413	451
Total other current liabilities	2,219	3,061
Other Ownership Interest [Member]
Other Current Liabilities [Line Items]
Minimum gathering volume commitment	27	21
Bank of New York Melton legal accrual [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	439	100
Oklahoma Royalty Settlement [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	$ 0	$ 119

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Long-Term Liabilities [Line Items]
Financing obligations	$ 29	$ 30
Unrecognized Tax Benefits	280	303	$ 644	$ 599
Other long-term liabilities	126	249
Total other long-term liabilities	409	679
Total other current liabilities	2,219	3,061
Other Noncurrent Liabilities [Member]
Other Long-Term Liabilities [Line Items]
Unrecognized Tax Benefits	64	45
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	190	220
Total other long-term liabilities	211	234
Total other current liabilities	21	14
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	$ 0	135
Total other long-term liabilities		158
Total other current liabilities		$ 23

Income Taxes Income Taxes - Inc

Income Taxes Income Taxes - Income Tax Expense Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ 0
Current State and Local Tax Expense (Benefit)	(36)	47	22
Current Income Tax Expense (Benefit)	(36)	47	22
Deferred Federal Income Tax Expense (Benefit)	(4,385)	1,115	502
Deferred State and Local Income Tax Expense (Benefit)	(42)	(18)	24
Deferred Income Tax Expense (Benefit)	(4,427)	1,097	526
Total Income Tax Expense (Benefit)	$ (4,463)	$ 1,144	$ 548

Income Taxes Income Taxes - Eff

Income Taxes Income Taxes - Effective Income Tax Expense Reconcile Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ (6,684)	$ 1,120	$ 505
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Amount	(406)	68	88
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	0	(114)	(38)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	2,727	74	(12)
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	(100)	(4)	5
Total Income Tax Expense (Benefit)	$ (4,463)	$ 1,144	$ 548

Income Taxes Income Taxes - Def

Income Taxes Income Taxes - Deferred Assets and Liabilities Reconcile Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred Tax Liabilities, Property, Plant and Equipment	$ 0	$ (3,829)
Deferred Tax Liabilities,Volumetric Production Payments	(802)	(1,023)
Deferred Tax Liabilities, Carrying Value of Debt	0	(443)
Deferred Tax Liabilities, Derivative Instruments	(294)	(428)
Deferred Tax Liabilities, Other	(74)	(114)
Deferred Tax Liabilities, Gross	1,170	5,837
Deferred Tax Assets, Property, Plant and Equipment	1,140	0
Deferred Tax Assets, Operating Loss Carryforwards (Carrybacks)	1,556	945
Deferred Tax Assets, Carrying Value of Debt	535	0
Deferred Tax Assets, Asset Retirement Obligations	174	165
Deferred Tax Assets, Investments	132	84
Deferred Tax Assets, Accrued Liabilities	332	239
Deferred Tax Assets, Other	250	234
Deferred Tax Assets, Gross	4,119	1,667
Deferred Tax Liabilities, Valuation Allowance	(2,949)	(222)
Deferred Tax Assets (Liabilities), Net of Valuation Allowance	1,170	1,445
Deferred Tax Liabilities, Net, Noncurrent	0	(4,392)
Deferred Tax Assets (Liabilities), Net	$ 0	$ 4,392

Income Taxes Income Taxes - Unr

Income Taxes Income Taxes - Unrecognized Tax Benefits Reconcile Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Schedule of Unrecognized Tax Benefits Roll Forward	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows: 2015 2014 2013 ($ in millions) Unrecognized tax benefits at beginning of period $ 303 $ 644 $ 599 Additions based on tax positions related to the current year 27 13 15 Additions to tax positions of prior years — — 30 Reductions to tax positions of prior years (50 ) (354 ) — Unrecognized tax benefits at end of period $ 280 $ 303 $ 644
Unrecognized Tax Benefits, Beginning of Period	$ 303	$ 644	$ 599
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	27	13	15
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	0	0	30
Unrecognized Tax Benefits, Decrease Resulting from Prior Period Tax Positions	(50)	(354)	0
Unrecognized Tax Benefits, End of Period	$ 280	$ 303	$ 644

Income Taxes Income Taxes - Nar

Income Taxes Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes Summary [Line Items]
Effective Income Tax Rate Reconciliation, Deferred Remeasurement	$ 0	$ (114)	$ (38)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Amount	2,727	74	(12)
Other Tax Expense (Benefit)	2,800
Deferred Tax Assets, Gross	4,119	1,667
Deferred Tax Liabilities, Valuation Allowance	$ 2,949	222
Treasury Regulations Purchase of Stock	5.00%
Percentage Of Beneficial Interest Owned	50.00%
Unrecognized Tax Benefits	$ 280	303	$ 644	$ 599
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	20	5
Domestic Tax Authority [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	3,200
State and Local Jurisdiction [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	9,500
Deferred Tax Assets, Tax Credit Carryforwards	1,107	449
Unrecognized Tax Benefits	44	23
General Business Tax Credit Carryforward [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	31
Unrecognized Tax Benefits		$ 17
Windfall [Member]
Income Taxes Summary [Line Items]
Tax Credit Carryforward, Amount	$ 19
Internal Revenue Service (IRS) [Member] | Tax Year 2010 [Member]
Income Taxes Summary [Line Items]
Income Tax Examination, Year under Examination	2,010
Internal Revenue Service (IRS) [Member] | Tax Year 2013 [Member]
Income Taxes Summary [Line Items]
Income Tax Examination, Year under Examination	2,013
Internal Revenue Service and Other Taxing Authorities [Member] | Tax Year 2010 [Member]
Income Taxes Summary [Line Items]
Income Tax Examination, Year under Examination	2,010
Internal Revenue Service and Other Taxing Authorities [Member] | Tax Year 2007 [Member]
Income Taxes Summary [Line Items]
Income Tax Examination, Year under Examination	2,007
Internal Revenue Service and Other Taxing Authorities [Member] | Tax Year 2015 [Member]
Income Taxes Summary [Line Items]
Income Tax Examination, Year under Examination	2,015
Senior Notes [Member] | 8.00% Senior Secured Second Lien Notes Due 2022 [Member]
Income Taxes Summary [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	8.00%	8.00%

Related Party Transactions - Eq

Related Party Transactions - Equity Method Investees Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Twin Eagle Resource Management Llc [Member]
Related Party Transaction [Line Items]
Revenue from Related Parties	$ 0	$ 0	$ 666
Equity Method Investment, Ownership Percentage			30.00%
FTS International, Inc. [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 65	$ 220	$ 397

Equity - Common Stock Table (De

Equity - Common Stock Table (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Issued Beginning of Period	664,944,232	666,192,000	666,468,000
Restricted stock issuances (net of forfeitures and cancellations)	(163,000)	(2,529,000)	(599,000)
Stock option exercises	15,000	1,281,000	323,000
Common Stock, Shares, Issued End of Period	664,795,509	664,944,232	666,192,000

Equity Equity - Preferred Stock

Equity Equity - Preferred Stock Conversion Table (Details)	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares
5.75% Cumulative Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%
4.50% Cumulative Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	4.50%
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Stock Issue Date	Jun. 1, 2010
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Conversion of Preferred Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	39.6526%
Preferred Stock, Convertible, Conversion Price	$ 25.2190
Convertible Preferred Stock, Company's Conversion Right From Date	May 17, 2015
Conversion of Preferred Stock, Company Market Trigger | $	$ 32.7847
Preferred Stock [Member] | 5.75% Cumulative Convertible Preferred Stock Series A [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Stock Issue Date	May 10, 2010
Preferred Stock, Liquidation Preference Per Share	$ 1,000
Conversion of Preferred Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	38.3186%
Preferred Stock, Convertible, Conversion Price	$ 26.0970
Convertible Preferred Stock, Company's Conversion Right From Date	May 17, 2015
Conversion of Preferred Stock, Company Market Trigger | $	$ 33.9261
Preferred Stock [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Stock Issue Date	Sep. 15, 2005
Preferred Stock, Liquidation Preference Per Share	$ 100
Conversion of Preferred Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.4561%
Preferred Stock, Convertible, Conversion Price	$ 40.7152
Convertible Preferred Stock, Company's Conversion Right From Date	September 15, 2010
Conversion of Preferred Stock, Company Market Trigger | $	$ 52.9298
Preferred Stock [Member] | 5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Stock Issue Date	Nov. 15, 2005
Preferred Stock, Liquidation Preference Per Share	$ 100
Conversion of Preferred Stock, Holders Conversion Right	Any time
Preferred Stock Conversion Rate	2.7745%
Preferred Stock, Convertible, Conversion Price	$ 36.0431
Convertible Preferred Stock, Company's Conversion Right From Date	November 15, 2010
Conversion of Preferred Stock, Company Market Trigger | $	$ 46.8560
Preferred Stock [Member] | 4.50% or 5.00% (Series 2005B) Preferred Stock (Member) | Minimum [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Company Market Trigger, Shares | shares	250,000
Preferred Stock [Member] | 5.75% or 5.75% (Series A) Preferred Stock [Member] | Minimum [Member]
Class of Stock [Line Items]
Conversion of Preferred Stock, Company Market Trigger, Shares | shares	25,000

Equity - Convertible Preferred

Equity - Convertible Preferred Stock Table (Details) - shares	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Preferred stock, shares outstanding, beginning of period	7,251,515
Preferred stock, shares outstanding, end of period	7,251,515	7,251,515
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Preferred stock, shares outstanding, beginning of period	1,497,000	1,497,000	1,497,000
Preferred stock, shares outstanding, end of period	1,497,000	1,497,000	1,497,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Preferred stock, shares outstanding, beginning of period	1,100,000	1,100,000	1,100,000
Preferred stock, shares outstanding, end of period	1,100,000	1,100,000	1,100,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Preferred stock, shares outstanding, beginning of period	2,559,000	2,559,000	2,559,000
Preferred stock, shares outstanding, end of period	2,559,000	2,559,000	2,559,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Preferred stock, shares outstanding, beginning of period	2,096,000	2,096,000	2,096,000
Preferred stock, shares outstanding, end of period	2,096,000	2,096,000	2,096,000

Equity - AOCI Changes Net of Ta

Equity - AOCI Changes Net of Tax Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	$ (143)
Net Other Comprehensive Income	44	$ 19	$ 20
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)	(143)
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(143)	(167)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	20	1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	24	23
Net Other Comprehensive Income	44	24
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)	(143)	(167)
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	0	5
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	5
Net Other Comprehensive Income	0	(5)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	0	0	5
AOCI Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(143)	(162)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	20	1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	24	18
Net Other Comprehensive Income	44	19
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (99)	$ (143)	$ (162)

Equity - AOCI Reclassifications

Equity - AOCI Reclassifications Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL reserves, reclassifications from AOCI	$ 5,391	$ 10,354	$ 8,626
Gains (losses) on purchases or exchanges of debt, reclassifications from AOCI	279	(197)	(193)
Net gain (loss) on sales of investments reclassifications from AOCI	0	67	(7)
Total reclassification from AOCI	(14,635)	2,056	$ 894
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total reclassification from AOCI	24	18
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on sales of investments reclassifications from AOCI		(5)
Commodity Contract [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL reserves, reclassifications from AOCI	23	$ 23
Foreign Exchange Contract [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on purchases or exchanges of debt, reclassifications from AOCI	$ 1

Equity - Narrative (Details)

Equity - Narrative (Details)	12 Months Ended
	Dec. 31, 2015
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
4.50% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	4.50%
5.75% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%

Equity - Noncontrolling Interes

Equity - Noncontrolling Interests Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended			2 Months Ended	3 Months Ended	12 Months Ended
	Jul. 31, 2014USD ($)$ / shares	Mar. 30, 2012USD ($)awell	Oct. 31, 2011aCounties	Dec. 31, 2011USD ($)wellshares	Dec. 31, 2011USD ($)shares	Dec. 31, 2015USD ($)awellQuarter$ / sharesshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)shares	Dec. 31, 2012shares	Mar. 31, 2012shares	Nov. 30, 2011$ / sharesshares
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments						$ 10	$ 17	$ 44
Stockholders' Equity Attributable to Noncontrolling Interest						259	1,302
Net income (loss) attributable to noncontrolling interests						50	139	170
Repurchase of preferred shares of CHK Utica						$ 0	$ (447)	$ (69)
Common Stock, Shares, Issued | shares						664,795,509	664,944,232	666,192,000	666,468,000
Common stock, par value (usd per share) | $ / shares						$ 0.01	$ 0.01
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a		245,000
Payments for (Proceeds from) Investments		$ 1,250
Preferred Stock, Shares Issued | shares										1,250,000
Overriding Royalty Interest Percentage										3.75%
Stockholders' Equity Attributable to Noncontrolling Interest							$ 1,015
Net income (loss) attributable to noncontrolling interests						$ 50	75	$ 75
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well						300
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member] | Wells, Future Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well		1,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member] | Wells, Drilled Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well						190
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a			700,000
Payments for (Proceeds from) Investments				$ 1,250
Preferred Stock, Shares Issued | shares				1,250,000	1,250,000
Net income (loss) attributable to noncontrolling interests							43	79
Number Of Counties Present In Leasehold Land | Counties			13
Payments for Repurchase of Preferred Stock and Preference Stock	$ 1,254
Preferred Stock, Redemption Price Per Share | $ / shares	$ 1,189
Repurchase of preferred shares of CHK Utica						$ (447)
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ORRI [Member]
Noncontrolling Interest [Line Items]
Overriding Royalty Interest Percentage				3.00%	3.00%	3.00%
Number of Wells, Net | well				1,500		1,500
Percentage of increase in leasehold in which commitment to drill is not met						4.00%			4.00%
Spacing for Wells Drilled | a						150
Number of Wells Drilled, Net | well						499
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ORRI [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well						1,300
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a						29,000
Stockholders' Equity Attributable to Noncontrolling Interest						$ 259	287
Net income (loss) attributable to noncontrolling interests						$ 0	$ 24	$ 20
Common stock, par value (usd per share) | $ / shares											$ 19
Common Stock, Shares, Outstanding | shares						46,750,000
Percentage Of Beneficial Interest Owned						51.00%
Number of producing wells | well						69
Number of development wells drilled | well						106
Number Of Gross Acres | a						45,400
Maximum amount recoverable by trust under lien					$ 263	$ 27
Quarters of Paid Distributions | Quarter						14
Percentage of incentive distributions received						50.00%
Percentage of remaining cash available for distribution in excess of the incentive threshold						50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust						50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust						90.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Common Unit [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Issued | shares											23,000,000
Common Stock, Shares, Outstanding | shares						12,062,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Outstanding | shares						11,687,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Wells, Initial Number of Wells [Member]
Noncontrolling Interest [Line Items]
Number of development wells drilled | well						118

Equity - Noncontrolling Inter94

Equity - Noncontrolling Interests Distribution Table (Details) - Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] - $ / shares	3 Months Ended
	Aug. 31, 2015	May. 31, 2015	Feb. 28, 2015	Nov. 30, 2014	Aug. 31, 2014	May. 31, 2014	Feb. 28, 2014	Nov. 30, 2013	Aug. 31, 2012	May. 31, 2012	Feb. 29, 2012	Nov. 30, 2011
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Distribution Date	Nov. 30, 2015	Aug. 31, 2015	Jun. 1, 2015	Mar. 2, 2015	Dec. 1, 2014	Aug. 29, 2014	May 30, 2014	Mar. 3, 2014	Nov. 29, 2013	Aug. 29, 2013	May 31, 2013	Mar. 1, 2013
Common Unit [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	$ 0.3232	$ 0.3579	$ 0.3899	$ 0.4496	$ 0.5079	$ 0.5796	$ 0.6454	$ 0.6624	$ 0.6671	$ 0.6900	$ 0.6900	$ 0.6700
Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0.1432	$ 0.3010	$ 0.3772

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock Table (Details) - Restricted Stock [Member] - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period Start	10,091	13,400	18,899
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	7,095	5,049	9,189
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(4,157)	(4,803)	(12,897)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(2,574)	(3,555)	(1,791)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	10,455	10,091	13,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 21.20	$ 23.38	$ 23.72
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	13.90	25.92	19.68
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	21.70	27.17	21.32
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	16.98	28.09	22.86
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 17.31	$ 21.20	$ 23.38

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation Table (Details) - Employee Stock Option [Member]	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	4 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	39.91%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.33%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.91%

Share-Based Compensation - Stoc

Share-Based Compensation - Stock Option Activity Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period Start					4,599	5,268	481
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross					1,208	994	5,264
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period					(14)	(1,322)	(346)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period					(416)	(28)	(131)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares					0	(313)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End	5,377	4,599	5,268	481	5,377	4,599	5,268
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	2,045	1,304	1,552		2,045	1,304	1,552
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start					$ 19.55	$ 19.28	$ 12.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price					18.37	24.43	19.32
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price					18.13	18.71	10.82
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price					18.46	18.97	19.31
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price					0	21.05
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End	$ 19.37	$ 19.55	$ 19.28	$ 12.69	19.37	19.55	19.28
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 19.61	$ 18.71	$ 18.82		$ 19.61	$ 18.71	$ 18.82
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	5 years 9 months 18 days	7 years 10 days	6 years 7 months 29 days	11 months 16 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	5 years 26 days	5 years 8 months 13 days	1 year 11 months 19 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start					$ 5	$ 41	$ 2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value					0	11	3
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End	$ 0	$ 5	$ 41	$ 2	0	5	41
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0	$ 1	$ 13		$ 0	$ 1	$ 13

Share-Based Compensation - Eq98

Share-Based Compensation - Equity-Classified Compensation Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 89	$ 104	$ 150
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	43	46	60
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	23	29	52
Oil, Natural Gas and NGL Production Expenses Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	18	21
Marketing, Gathering and Compression Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	5	6	7
Oilfield Services Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 5	$ 10

Share-Based Compensation - Liab

Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Shares [Member]	12 Months Ended
	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	55.76%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.06%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%

Share-Based Compensation - Perf

Share-Based Compensation - Performance Share Unit Breakout (Details) - Performance Shares [Member] - USD ($) $ in Millions	Dec. 31, 2015	Jan. 01, 2015	Jan. 01, 2014	Jan. 01, 2013
Payable 2016 [Member] | Year of 2013 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,701,941
Fair Value of Share Based Award	$ 4			$ 35
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 4
Payable 2017 [Member] | Year of 2014 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	609,637
Fair Value of Share Based Award	$ 0		$ 16
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 0
Payable 2018 [Member] | Year of 2015 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	696,683
Fair Value of Share Based Award	$ 2	$ 13
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 1

Share-Based Compensation - L101

Share-Based Compensation - Liability-Classified Compensation Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 89	$ 104	$ 150
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	43	46	60
Marketing, Gathering and Compression Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	5	6	7
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	23	29	52
Oil, Natural Gas and NGL Production Expenses Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	18	18	21
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(41)	(20)	77
Performance Shares [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(19)	(4)	34
Performance Shares [Member] | Restructuring Charges [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(19)	(19)	29
Performance Shares [Member] | Marketing, Gathering and Compression Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(1)	0	2
Performance Shares [Member] | Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(2)	3	9
Performance Shares [Member] | Oil, Natural Gas and NGL Production Expenses Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	0	2
Performance Shares [Member] | Oilfield Services [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 0	$ 1

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	664,795,509	664,944,232	666,192,000	666,468,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 59
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 109
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 10 months 5 days
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 6 months 22 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Black-Scholes option pricing model
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	$ 8
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
TSR [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	Monte Carlo simulation
2014 Long Term Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	10 years
Reduction due to issuance of stock option or SAR	1
Reduction due to award other than stock option or SAR	2.12
Common Stock, Capital Shares Reserved for Future Issuance	35,350,862
2014 Long Term Incentive Plan [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	36,600,000
Year of 2014 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage		100.00%
Non-Employee Director [Member] | 2014 Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	225,630	50,771
Non-Employee Director [Member] | 2003 Stock Award Plan for Non-Employee Directors [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common Stock, Shares Authorized	250,000
Common Stock, Shares, Issued	10,000
Employee [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Employee [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Employee [Member] | 2014 Long Term Incentive Plan [Member] | Restricted Stock Units (RSUs) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	5,440,420	272,289
Share Based Compensation, Option to Purchase, Shares		1,208,185
Management [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	33.00%
Management [Member] | Employee Stock Option [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	7 years
Management [Member] | Employee Stock Option [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	10 years
Management [Member] | Stock Option Award Three Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Management [Member] | Stock Optioin Award Four Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	4 years
Management [Member] | Stock option Award Five Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	5 years
Management [Member] | Years of 2013 and 2014 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights		third
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	125.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	62.50%
Management [Member] | Year of 2014 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Management [Member] | Year of 2014 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	200.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	100.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	0.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage	50.00%
Common Stock [Member] | Non-Employee Director [Member] | 2003 Stock Award Plan for Non-Employee Directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Shares Issued in Period	10,000	10,000	20,000
Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation	$ (12)	$ 15	$ (13)
Paid-In Capital [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase (decrease) in tax benefit from stock-based compensation		12
Decrease in tax benefit from stock-based compensation	$ 12		14
Paid-In Capital [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Decrease in tax benefit from stock-based compensation		$ 3	$ 1

Employee Benefit Plans Employee

Employee Benefit Plans Employee Benefit Plans Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Contribution Plan Disclosure [Line Items]
Pension and Other Postretirement Defined Benefit Plans, Current Liabilities	$ 3,000,000
Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 52,000,000	$ 61,000,000	$ 81,000,000
Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan [Member] | Maximum [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	15.00%
DC Plan [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	15.00%
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 11,000,000	$ 7,000,000	$ 14,000,000
Defined Benefit Plans, General Information	55
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	100.00%
Deferred Compensation Arrangement with Individual, Requisite Service Period	5 years
DC Plan [Member] | Deferred Compensation, Excluding Share-based Payments and Retirement Benefits [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
DC Plan [Member] | Deferred Bonus [Member]
Defined Contribution Plan Disclosure [Line Items]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	100.00%
DC Plan [Member] | Maximum [Member]
Defined Contribution Plan Disclosure [Line Items]
Top wage earners percentage of employees eligible to participate	10.00%
DC Plan [Member] | Minimum [Member]
Defined Contribution Plan Disclosure [Line Items]
Salaries, Wages and Officers' Compensation	$ 150,000

Derivative and Hedging Activ104

Derivative and Hedging Activities - Derivative Instruments Table (Details) MMBbls in Millions, $ in Millions, MMBTU in Trillions	Dec. 31, 2014USD ($)MMBTUMMBbls	Dec. 31, 2015USD ($)MMBTUMMBbls
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 652	$ 512
Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	52.7	32.7
Derivative Assets (Liabilities), at Fair Value, Net	$ 422	$ 137
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	12.5	13.5
Derivative Assets (Liabilities), at Fair Value, Net	$ 471	$ 144
Crude Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	4.4	0
Derivative Assets (Liabilities), at Fair Value, Net	$ 40	$ 0
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	35.8	19.2
Derivative Assets (Liabilities), at Fair Value, Net	$ (89)	$ (7)
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	0	0
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0
Natural Gas [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 299	$ 130
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	735	852
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 281	$ 229
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	275	500
Natural Gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 165	$ 0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	207	0
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (170)	$ (99)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	193	295
Natural Gas [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 23	$ 0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	60	57

Derivative and Hedging Activ105

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 512	$ 652
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	512	652
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	267	721
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	267	721
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	267	721
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(17)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(17)
Not Designated as Hedging Instrument [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	297	1
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	297	1
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	381	973
Derivative Asset, Fair Value, Gross Liability	(66)	(95)
Derivative, Fair Value, Net	315	878
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	51	1
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	51	1
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0	16
Derivative Asset, Fair Value, Gross Liability	0	(10)
Derivative, Fair Value, Net	0	6
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	246	0
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	246	0
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(106)	(105)
Derivative Liability, Fair Value, Gross Asset	66	95
Derivative, Fair Value, Net	(40)	(10)
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(5)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(5)
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(8)	(163)
Derivative Liability, Fair Value, Gross Asset	0	10
Derivative, Fair Value, Net	(8)	(153)
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(12)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(12)
Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(52)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	(52)	(53)
Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(52)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	$ (52)	$ (53)

Derivative and Hedging Activ106

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	$ 9	$ 81	$ (63)
Total oil, natural gas and NGL revenues	5,391	10,354	8,626
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL revenues	4,767	9,336	8,497
Gains (losses) on undesignated oil and natural gas derivatives	661	1,055	443
Losses on terminated cash flow hedges	$ (37)	$ (37)	$ (314)

Derivative and Hedging Activ107

Derivative and Hedging Activities Derivative and Hedging Activities, Marketing, Gathering and Compression Sales (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Total Marketing, Gathering and Compression Revenues	$ 7,373	$ 12,225	$ 9,559
Marketing, Gathering And Compression [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Refining and Marketing Revenue	7,077	12,224	9,559
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net		0
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net	$ 296	$ 1	$ 0

Derivative and Hedging Activ108

Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$ 682	$ 704	$ 740
Interest expense on term loan	0	36	116
Amortization of loan discount, issuance costs and other	59	42	91
Interest expense on credit facilities	12	28	38
Gains on terminated fair value hedges	(3)	(3)	(5)
(Gains) losses on undesignated interest rate derivatives	(9)	(81)	63
Capitalized interest	(424)	(637)	(816)
Total interest expense	$ 317	$ 89	$ 227

Derivative and Hedging Activ109

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	$ (143)
Other Comprehensive Income (Loss), Net Change in Fair Value, Net of Tax	20	$ 1	$ 2
Other Comprehensive Income (Loss), Losses Reclassified to Income, Net of Tax	24	23	20
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)	(143)
Cash Flow Hedging [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period Start	(231)	(269)	(304)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(143)	(167)	(189)
Other Comprehensive Income (Loss), Net Change in Fair Value, Before Tax	32	1	3
Other Comprehensive Income (Loss), Losses Reclassified to Income, Before Tax	39	37	32
Other Comprehensive Income (Loss), Losses Reclassified to Income, Net of Tax	24	23	20
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(160)	(231)	(269)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (99)	$ (143)	$ (167)

Derivative and Hedging Activ110

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 512	$ 652
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	381	989
Derivative Liability	(114)	(268)
Derivative Assets (Liabilities), at Fair Value, Net	267	721
Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	(17)
Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	(52)	(53)
Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	297	1
Fair Value, Inputs, Level 1 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	306	705
Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	372	784
Derivative Liability	(14)	(9)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	(17)
Fair Value, Inputs, Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	(52)	(53)
Fair Value, Inputs, Level 2 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	206	(53)
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	9	205
Derivative Liability	(100)	(259)
Derivative Assets (Liabilities), at Fair Value, Net	(91)	(54)	$ (478)
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	297	1
Derivative Assets (Liabilities), at Fair Value, Net	$ 297	$ 1	$ 0

Derivative and Hedging Activ111

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	$ 652
Derivative Assets (Liabilities), at Fair Value, Net, Period End	512	$ 652
Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	721
Derivative Assets (Liabilities), at Fair Value, Net, Period End	267	721
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	(53)
Derivative Assets (Liabilities), at Fair Value, Net, Period End	206	(53)
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	(54)	(478)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	100
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(137)	136
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net		(4)
Derivative Assets (Liabilities), at Fair Value, Net, Period End	(91)	(54)	$ (478)
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member] | Oil And Gas Exploration And Production [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	100	292
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	43	262
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	1	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	316
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(20)	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net		0
Derivative Assets (Liabilities), at Fair Value, Net, Period End	297	1	0
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member] | Marketing, Gathering And Compression [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net	296	1	$ 0
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	$ 296	$ 0

Derivative and Hedging Activ112

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Energy Related Derivative, Oil Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	35.52%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (7)
Energy Related Derivative, Oil Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	26.87%
Energy Related Derivative, Oil Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	43.08%
Other Contract [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	24.07%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 297
Other Contract [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	20.01%
Other Contract [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	43.81%
Energy Related Derivative, Natural Gas Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	34.29%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (84)
Energy Related Derivative, Natural Gas Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	19.84%
Energy Related Derivative, Natural Gas Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	73.05%

Derivative and Hedging Activ113

Derivative and Hedging Activities - Narrative (Details) € in Millions, MMBoe in Millions, $ in Millions, MMBTU in Billions	1 Months Ended		12 Months Ended
	Dec. 31, 2015USD ($)MMBoecounterpartyDerivatives$ / €	Dec. 31, 2006USD ($)$ / €	Dec. 31, 2015USD ($)MMBoeMMBTUcounterpartyDerivatives$ / €	Dec. 31, 2014USD ($)$ / €	Dec. 31, 2013USD ($)	Dec. 31, 2015EUR (€)MMBoecounterpartyDerivatives$ / €	Apr. 30, 2015USD ($)	Apr. 24, 2014USD ($)	Dec. 31, 2012USD ($)	Dec. 31, 2006EUR (€)$ / €
Derivative [Line Items]
Number of Interest Rate Derivatives Held | Derivatives	0		0			0
Derivative Assets (Liabilities), at Fair Value, Net	$ 512		$ 512	$ 652
Cash paid to purchase debt			(508)	(3,362)	$ (2,141)
Debt Instrument, Face Amount	9,706		9,706	11,756
Accumulated other comprehensive loss	99		99	143
Expected amount to be transferred of during the next 12 months	21		21
Senior Notes [Member]
Derivative [Line Items]
Gain (Loss) on Repurchase of Debt Instrument					37
Debt Instrument, Face Amount				3,000	2,300			$ 3,000
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Debt Instrument, Face Amount	$ 329		$ 329	416
Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty	3		3			3
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier	1.30		1.30			1.30
Borrowing capacity	$ 1,500		$ 1,500
Multi-Counterparty Hedging Facility [Member] | Minimum [Member]
Derivative [Line Items]
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier	1.65		1.65			1.65
Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Borrowing capacity							$ 16,500
Line of Credit Facility, Current Borrowing Capacity	$ 1,500		$ 1,500
Cash Flow Hedging [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	99		99	143	$ 167				$ 189
Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	(113)		$ (113)
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, Amount of Hedged Item				850
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge			6 years
Deferred (Gain) Loss on Discontinuation of Fair Value Hedge	7		$ 7
Debt Instrument, Face Amount	0		0	0
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net				(17)
Derivative Liability, Fair Value, Gross Liability				$ (17)
Cross Currency Interest Rate Contract [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Gain (Loss) on Repurchase of Debt Instrument	(8)
Debt Instrument, Repurchased Face Amount	42		$ 42
Cash paid to purchase debt	$ (8)
Derivative, Forward Exchange Rate | $ / €	1.0862	1.3325	1.0862	1.2098		1.0862				1.3325
Semi Annual Interest Rate Swap Payments By Counterparty | €						€ 302				€ 9
Dollar Equivalent Interest Rate		7.491%
Short-term Debt, Refinanced, Description	$ 403	$ 15	$ 403
Foreign Exchange Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(52)		(52)	$ (53)
Derivative Liability, Fair Value, Gross Liability	$ (52)		$ (52)	(53)
Other Contracts, A [Member]
Derivative [Line Items]
Derivative, Number of Instruments Held | Derivatives	1		1			1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements			$ 96
Other Contracts, A [Member] | Minimum [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU			90
Credit Risk [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty	16		16			16
Energy Related Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe) | MMBoe	94		94			94
Price Risk Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe	1.2		1.2			1.2
Price Risk Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe	164		164			164
Basis Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe) | MMBoe	94		94			94
Basis Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe	9.5		9.5			9.5
Fair Value, Inputs, Level 3 [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 206		$ 206	$ (53)
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contracts, A [Member]
Derivative [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings			$ 297

Oil and Natural Gas Property114

Oil and Natural Gas Property Transactions - VPP Transactions Table (Details) Mcfe in Millions, Mcf in Millions, MBbls in Millions, $ in Millions	3 Months Ended						12 Months Ended
	Mar. 31, 2012USD ($)McfeMBblsMcf	Jun. 30, 2011USD ($)	Dec. 31, 2008USD ($)McfeMBblsMcf	Sep. 30, 2008USD ($)	Jun. 30, 2008USD ($)	Dec. 31, 2007USD ($)McfeMBblsMcf	Dec. 31, 2015USD ($)McfeMBblsMcf	May. 31, 2011McfeMBblsMcf	Aug. 31, 2008McfeMBblsMcf	May. 31, 2008McfeMBblsMcf
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $							$ 4,331
Proved Developed Reserves (Energy) | Mcfe							830
Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)							5.2
Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf							715
Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)							14
VPP 10 Aradarko Basin Granite Wash [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $	$ 744
Proved Developed Reserves (Energy) | Mcfe	160
VPP 10 Aradarko Basin Granite Wash [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)	3
VPP 10 Aradarko Basin Granite Wash [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf	87
VPP 10 Aradarko Basin Granite Wash [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)	9.2
VPP 9 Mid-Continent [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $		$ 853
Proved Developed Reserves (Energy) | Mcfe								177
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)								1.7
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf								138
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)								4.8
VPP 4 Anadarko and Arkoma Basins [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $			$ 412
Proved Developed Reserves (Energy) | Mcfe			98
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)			0.5
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf			95
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)			0
VPP 3 Anadarko Basin [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $				$ 600
Proved Developed Reserves (Energy) | Mcfe									93
VPP 3 Anadarko Basin [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)									0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf									93
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)									0
VPP 2 Texas, Oklahoma and Kansas [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $					$ 622
Proved Developed Reserves (Energy) | Mcfe										94
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf										94
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)										0
VPP 1 Kentucky and West Virginia [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $						$ 1,100
Proved Developed Reserves (Energy) | Mcfe						208
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)						0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf						208
VPP 1 Kentucky and West Virginia [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)						0

Oil and Natural Gas Property115

Oil and Natural Gas Property Transactions - VPP Volumes Produced During Period Table (Details) Mcfe in Millions, Mcf in Millions	12 Months Ended
	Dec. 31, 2015McfeMBblsMcf	Dec. 31, 2014McfeMBblsMcf	Dec. 31, 2013McfeMBblsMcf
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	102.4	145.2	170.9
Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	520,400	678,200	864,300
Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	90.9	131.1	154
Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,419,800	1,707,500	1,964,700
VPP 10 Anadarko Basin Granite Wash [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	16.6	20.7	25.8
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	310,000	403,000	547,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	8.5	10.6	13.5
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	1,043,900	1,296,500	1,509,000
VPP 9 Mid-Continent [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	17.4	19	21
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	167,900	187,500	213,200
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	14.2	15.4	17
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	375,900	411,000	455,700
VPP 8 Barnett Shale [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	36.5	60.1	68.1
VPP 8 Barnett Shale [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	36.5	60.1	68.1
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 6 East Texas and Texas Gulf Coast [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe		4.3	4.9
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		23,100	24,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf		4.2	4.8
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		0	0
VPP 5 South Texas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe		4.7	7.7
VPP 5 South Texas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		16,500	25,400
VPP 5 South Texas [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf		4.6	7.5
VPP 5 South Texas [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		0	0
VPP 4 Anadarko and Arkoma Basins [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	8.2	9.2	10.5
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	42,500	48,100	54,700
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	8	9	10.2
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	6.4	7.2	8.1
VPP 3 Anadarko Basin [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	6.4	7.2	8.1
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4	6.2	10.3
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	4	6.2	10.3
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	13.3	13.8	14.5
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	13.3	13.8	14.5
VPP 1 Kentucky and West Virginia [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0

Oil and Natural Gas Property116

Oil and Natural Gas Property Transactions - VPP Volume Remaining to Be Delivered Table (Details) Mcfe in Millions, Mcf in Millions, MMBbls in Millions, MBbls in Millions	12 Months Ended
	Dec. 31, 2015McfeMBblsMMBblsMcf	May. 31, 2011McfeMBblsMcf	Dec. 31, 2008McfeMBblsMcf	Aug. 31, 2008McfeMBblsMcf	May. 31, 2008McfeMBblsMcf	Dec. 31, 2007McfeMBblsMcf
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe	830
Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe	243
Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls	5.2
Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	1.7
Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	715
Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	201.5
Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls	14
Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	5.2
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	74 months
Proved Developed Reserves (Energy) | Mcfe	57.4
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	1
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	29.6
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	3.6
VPP 9 Mid-Continent [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe		177
VPP 9 Mid-Continent [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	62 months
Proved Developed Reserves (Energy) | Mcfe	72.4
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls		1.7
VPP 9 Mid-Continent [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0.7
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf		138
VPP 9 Mid-Continent [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	59
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls		4.8
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	1.6
VPP 4 Anadarko and Arkoma Basins [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe			98
VPP 4 Anadarko and Arkoma Basins [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	12 months
Proved Developed Reserves (Energy) | Mcfe	7.6
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls			0.5
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf			95
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	7.3
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls			0
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe				93
VPP 3 Anadarko Basin [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	43 months
Proved Developed Reserves (Energy) | Mcfe	17.5
VPP 3 Anadarko Basin [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls				0
VPP 3 Anadarko Basin [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf				93
VPP 3 Anadarko Basin [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	17.5
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls				0
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe					94
VPP 2 Texas, Oklahoma and Kansas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	40 months
Proved Developed Reserves (Energy) | Mcfe	9.8
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls					0
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf					94
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	9.8
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls					0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe						208
VPP 1 Kentucky and West Virginia [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	84 months
Proved Developed Reserves (Energy) | Mcfe	78.3
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls						0
VPP 1 Kentucky and West Virginia [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf						208
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	78.3
VPP 1 Kentucky and West Virginia [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls						0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0

Oil and Natural Gas Property117

Oil and Natural Gas Property Transactions - Narrative (Details)	Oct. 15, 2014awell	Mar. 30, 2012a	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)awellCompressor	Dec. 31, 2013USD ($)a	Jun. 30, 2013Resource_PlaysJoint_Venture
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			$ 189,000,000	$ 5,813,000,000	$ 3,467,000,000
Other Customers [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			66,000,000
Southwestern [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 4,975,000,000
Number Of Net Acres | a	413,000
RKI Exploration & Production, LLC [Member]
Business Acquisition [Line Items]
Number Of Gross Acres | a				440,000
RKI Exploration & Production, LLC [Member] | Chesapeake Obligation [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 450,000,000
Number Of Net Acres | a				137,000
Number of Wells, Gross | well				67
Interest Sold				22.00%
RKI Exploration & Production, LLC [Member] | RKI Obligation [Member]
Business Acquisition [Line Items]
Number Of Net Acres | a				203,000
Number of Wells, Gross | well				186
Interest Sold				48.00%
Rice Drilling [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 233,000,000
Hilcorp Energy [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 133,000,000
Equipment, Number of Units | Compressor				61
Haynesville Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres | a					9,600
Northern Eagle Ford Shale [Member]
Business Acquisition [Line Items]
Number Of Net Acres | a					55,000
Payment at Closing [Member] | MKR Holdings LLC [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties					$ 490,000,000
Payment at Closing [Member] | Haynesville Shale [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties					257,000,000
Payment at Closing [Member] | Northern Eagle Ford Shale [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties					617,000,000
Subsequent Payment [Member] | Haynesville Shale [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties					47,000,000
Subsequent Payment [Member] | Northern Eagle Ford Shale [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 57,000,000	$ 32,000,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			90,000,000
Number Of Net Acres | a		245,000
VPP 6 East Texas and Texas Gulf Coast [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				63,000,000
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				379,000,000
Number Of Net Acres | a					850,000
Number of Joint Ventures | Joint_Venture						8
Number of Resource Plays | Resource_Plays						8
Proceeds from Divestiture of Interest in Joint Venture			8,000,000,000
Total Drilling Carries			9,000,000,000
Oil And Gas Benefit From Drilling Carries			51,000,000	679,000,000	$ 884,000,000
Corporate Joint Venture [Member] | Minimum [Member]
Business Acquisition [Line Items]
Interest Sold						20.00%
Corporate Joint Venture [Member] | Maximum [Member]
Business Acquisition [Line Items]
Interest Sold						50.00%
JV Mississippian Lime [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture					$ 1,110,000,000
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners					50.00%
JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture			33,000,000	$ 33,000,000	$ 58,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets			$ 0
North Western Virginia and Southern Pennsylvania [Member] | Southwestern [Member]
Business Acquisition [Line Items]
Number of Wells, Gross | well	1,500
Marcellus and Utica Formations [Member] | Southwestern [Member]
Business Acquisition [Line Items]
Number of Wells, Gross | well	435

Spin-Off of Oilfield Service118

Spin-Off of Oilfield Services Business - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross		$ 10,735		$ 11,535
Operating Leases, Future Minimum Payments Due		9
Stockholders' equity decreased amount				(270)
Restructuring and other termination costs		$ 36		7	$ 248
Drilling Rig Leases [Member] | Minimum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Lease Term		3 months
Drilling Rig Leases [Member] | Maximum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Lease Term		3 years
Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stockholders' Equity Note, Stock Split	one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred Tax Liabilities, Deferred Expense				151
Restructuring and other termination costs		$ 0		$ 15	$ 0
Seven Seven Energy Inc. [Member] | Drilling Rig Leases [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Leases, Future Minimum Payments Due		$ 227
Seven Seven Energy Inc. [Member] | Drilling Rig Leases [Member] | Minimum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Lease Term		3 months
Seven Seven Energy Inc. [Member] | Drilling Rig Leases [Member] | Maximum [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Lease Term		3 years
Seven Seven Energy Inc. [Member] | Secured Debt [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	$ 400
Seven Seven Energy Inc. [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2022 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	$ 500
Debt Instrument, Interest Rate, Stated Percentage	6.50%
General Partner Distributions			$ 391
Seven Seven Energy Inc. [Member] | Seven Seven Energy Inc. Revolving Credit Facility [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity	$ 275

Investments - Schedule of Inves

Investments - Schedule of Investments Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Carrying Value of Investments	$ 136	$ 265
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Carrying Value of Investments	$ 119	$ 130
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Carrying Value of Investments	$ 0	$ 116
Other Investment Companies [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	0.00%
Carrying Value of Investments	$ 17	$ 19

Investments - Narrative (Detail

Investments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$ 0	$ 239	$ 115
Impairments of investments	53	5	10
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	20
Interest Costs Capitalized	9
Excess carrying value of investment over underlying equity in net assets	87
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	107
Equity method accretion adjustments	$ 44
Chaparral Energy Inc [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments		209
Equity Method Investment, Realized Gain (Loss) on Disposal		73
Clean Energy Fuels Corp [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments			13
Equity Method Investment, Realized Gain (Loss) on Disposal			3
Cost Method Investments			100
Other Commitment			50
Impairments of investments			15
Clean Energy Fuels Corp [Member] | Convertible Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments			85
Gastar Exploration Ltd [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Net Sales Proceeds			10
Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments		30	6
Equity Method Investment, Realized Gain (Loss) on Disposal		$ (6)	$ 5

Variable Interest Entities - Na

Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Variable Interest Entity [Line Items]
VIE, Cash and cash equivalents	$ 825	$ 4,108	$ 837	$ 287
VIE. proved natural gas and oil properties	63,843	58,594
VIE. accumulated depreciation, depletion and amortization	(59,365)	(39,043)
VIE. other current liabilities	2,219	3,061
Non-Guarantor Subsidiaries [Member]
Variable Interest Entity [Line Items]
VIE, Cash and cash equivalents	1	84	$ 38	$ 59
VIE. other current liabilities	8	58
Variable Interest Entities, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
VIE, Cash and cash equivalents	1	1
VIE. proved natural gas and oil properties	488	488
VIE. accumulated depreciation, depletion and amortization	(428)	(251)
VIE. other current liabilities	$ 8	$ 15
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	10.00%
Variable interest entity, carrying value of investment	$ 10
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Minimum [Member]
Variable Interest Entity [Line Items]
Royalty percentage minimum	7.00%
Royalty percentage maximum	7.00%
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 25
Royalty percentage minimum	22.50%
Royalty percentage maximum	22.50%
Majority-Owned Subsidiary, Unconsolidated [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	90.00%
Majority-Owned Subsidiary, Unconsolidated [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 225

Other Property and Equipment Ot

Other Property and Equipment Other Property and Equipment - Held for Use and Estimated Useful Lives Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Land	$ 289	$ 296
Total other property and equipment, at cost	2,927	3,083
Property, Plant and Equipment, Other, Accumulated Depreciation	813	804
Property, Plant and Equipment, Other, Net	2,114	2,279
Building and Building Improvements [Member]
Property, Plant and Equipment [Line Items]
Buildings and Improvements, Gross	$ 1,209	1,242
Property, Plant and Equipment, Estimated Useful Lives	10 – 39
Natural Gas Compressor [Member]
Property, Plant and Equipment [Line Items]
Machinery and Equipment, Gross	$ 483	551
Property, Plant and Equipment, Estimated Useful Lives	3 – 20
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Machinery and Equipment, Gross	$ 214	218
Property, Plant and Equipment, Estimated Useful Lives	20
Property, Plant and Equipment, Other Types [Member]
Property, Plant and Equipment [Line Items]
Other property and equipment	$ 732	$ 776
Property, Plant and Equipment, Estimated Useful Lives	2 – 20

Other Property and Equipment -

Other Property and Equipment - Net Gains (Losses) on Sales of Fixed Assets Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Other, Accumulated Depreciation	$ (813)	$ (804)
Net (gains) losses on sales of fixed assets	4	(199)	$ (302)
Other property and equipment, net	2,114	2,279
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	3	(2)	27
Natural Gas Compressor [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	(195)	0
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	1	8	(326)
Oilfield Services Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	(7)	2
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 0	$ (3)	$ (5)

Other Property and Equipment124

Other Property and Equipment - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Compressor	Dec. 31, 2014USD ($)CompressorRigs	Dec. 31, 2013USD ($)Rigs
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 4	$ (199)	$ (302)
Property and equipment held for sale, net	95	93
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	3	(2)	27
Land and Building [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Property and equipment held for sale, net	95	93
Natural Gas Compressor [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment	40	693
Net (gains) losses on sales of fixed assets	$ 0	$ (195)	0
Equipment, Number of Units | Compressor	465	703
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 1	$ 8	(326)
Gathering and Processing Equipment [Member] | SemGroup Corporation [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			306
Net (gains) losses on sales of fixed assets		(141)
Gathering and Processing Equipment [Member] | Granite Wash Midstream Gas Services, L.L.C. [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			252
Net (gains) losses on sales of fixed assets			(105)
Gathering and Processing Equipment [Member] | Western Gas Partners, LP [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment			134
Net (gains) losses on sales of fixed assets			(55)
Oilfield Services Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 0	(7)	$ 2
Equipment, Number of Units | Rigs			23
Oilfield Services Equipment [Member] | Oilfield Services [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		44
Net (gains) losses on sales of fixed assets		(23)
Drilling Rigs [Member] | Oilfield Services [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		14
Net (gains) losses on sales of fixed assets		$ 14
Equipment, Number of Units | Rigs		14

Impairments Impairments - Fixed

Impairments Impairments - Fixed Assets and Other Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	$ 194	$ 88	$ 546
Natural Gas Compressor [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	21	11	0
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	0	18	366
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	0	13	22
Oilfield Services Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	0	23	71
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	$ 173	$ 23	$ 87

Impairments - Narrative (Detail

Impairments - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Compressor	Dec. 31, 2014USD ($)CompressorRigs	Dec. 31, 2013USD ($)Rigs
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Leasehold	$ 1,900
Impairment of oil and natural gas properties	18,238	$ 0	$ 0
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	176
Impairments of fixed assets and other	194	88	546
Gain (Loss) on Contract Termination	18
Provision for legal contingencies	340	234	0
Third Party [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Gain (Loss) on Contract Termination			15
Contractual Dispute [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	47
Note Receivable [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	22
Net Acreage Shortfall [Member] | Total [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for legal contingencies	70
Other Cost and Expense, Operating		22
Natural Gas Compressor [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$ 21	$ 11	0
Equipment, Number of Units | Compressor	465	703
Proceeds from Sale of Property, Plant, and Equipment	$ 40	$ 693
Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	0	18	366
Oilfield Services Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	0	$ 23	$ 71
Equipment, Number of Units | Rigs			23
Leased Equipment Purchased | Rigs		31
Payments to Acquire Property, Plant, and Equipment		$ 140	$ 141
Gain (Loss) on Contract Termination		(8)	22
Impairment of Long-Lived Assets to be Disposed of			27
Oilfield Services Leasehold an Improvements [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other		15
Impairment of Long-Lived Assets to be Disposed of			22
Gathering and Processing Equipment [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$ 0	$ 13	22
Other Asset Impairment Charges			26
In the Oklahoma City Area [Member] | Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			186
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down			69
In the Fort Worth Area [Member] [Member] | Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			10
In the Fort Worth Area [Member] [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member] | Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			86
Outside the Oklahoma City and Ft. Worth Areas [Member] | Land and Building [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other			15
Selling and Marketing Expense [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Other Asset Impairment Charges			$ 28

Restructuring Restructuring 127

Restructuring Restructuring and Other Termination Costs Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Debt extinguishment costs	$ 508	$ 3,362	$ 2,141
Restructuring and other termination costs	36	7	248
Severance Costs			50
Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	(8)	(8)	69
Severance Costs			69
Cash Salary and Bonus Costs [Member] | Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	11
Claw-Back Bonus [Member] | Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	11
Acceleration of Restricted Stock Awards [Member] | Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	22
Acceleration of Performance Shares [Member] | Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	(8)	(8)	18
Other Costs Associated with Retirement [Member] | Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	7
Other, Including PSU's [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	(11)	0	50
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Restructuring Cost and Reserve [Line Items]
Business Exit Costs	0	17	0
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options	0	5	0
Stock Granted, Value, Share-based Compensation, Forfeited	0	(10)	0
Debt extinguishment costs	0	3	0
Restructuring and other termination costs	0	15	0
Workforce Reduction Plan [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost			66
Restructuring and other termination costs	55	0	66
Workforce Reduction Plan [Member] | Salary Expense [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	47	0	20
Workforce Reduction Plan [Member] | Acceleration of Stock-Based Compensation Awards [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	0	0	45
Workforce Reduction Plan [Member] | Other Restructuring [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and Related Cost, Incurred Cost	8	0	1
VSP Program [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	0	0	63
Severance Costs			63
VSP Program [Member] | Cash Salary and Bonus Costs [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	33
VSP Program [Member] | Acceleration of Restricted Stock Awards [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0	29
VSP Program [Member] | Other Costs Associated with Retirement [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 0	$ 0	$ 1

Restructuring Restructuring 128

Restructuring Restructuring and Other Termination Costs - Narrative (Details) $ in Millions	Sep. 29, 2015	Dec. 30, 2012Employee	Feb. 28, 2013Employee	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)Employee
Restructuring Cost and Reserve [Line Items]
Restructuring, Percentage of Employees Effected	15.00%
Restructuring and other termination costs				$ 36	$ 7	$ 248
Restructuring and Related Cost, Number of Positions Eliminated | Employee						900
Severance Costs						$ 50
Allocated Share-based Compensation Expense				89	104	150
Performance Shares [Member]
Restructuring Cost and Reserve [Line Items]
Allocated Share-based Compensation Expense				(41)	(20)	77
Restructuring Charges [Member] | Performance Shares [Member]
Restructuring Cost and Reserve [Line Items]
Allocated Share-based Compensation Expense				(19)	(19)	29
Former CEO [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				(8)	(8)	69
Severance Costs						69
Workforce Reduction Plan [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				55	0	66
Restructuring and Related Cost, Incurred Cost						66
VSP Program [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				0	0	63
Restructuring and Related Cost, Number of Positions Eliminated | Employee		275	211
Severance Costs						63
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				55
Spinoff [Member] | Seven Seven Energy Inc. [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				$ 0	$ 15	$ 0

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	$ (1)	$ (1)
Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	50	57
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(51)	(58)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	(1)	(1)
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	50	57
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(51)	(58)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	$ 0	$ 0

Asset Retirement Obligations130

Asset Retirement Obligations Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Period Start	$ 465	$ 405
Additions to Asset Retirement Obligations	6	29
Revisions to Asset Retirement Obligations	13	101
Settlements and disposals, Asset Retirement Obligations	(34)	(92)
Accretion Expense, Asset Retirement Obligations	23	22
Asset Retirement Obligation, Period End	473	465
Asset Retirement Obligation, Current	21	18
Asset retirement obligations, net of current portion	$ 452	$ 447

Major Customers and Segment 131

Major Customers and Segment Information - Table (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Total Revenues	$ 12,764,000,000	$ 23,125,000,000	$ 19,080,000,000
Depreciation, depletion and amortization	2,229,000,000	2,915,000,000	2,903,000,000
Impairment of oil and natural gas properties	18,238,000,000	0	0
Impairments of fixed assets and other	194,000,000	88,000,000	546,000,000
Net (gains) losses on sales of fixed assets	4,000,000	(199,000,000)	(302,000,000)
Interest expense	(317,000,000)	(89,000,000)	(227,000,000)
Losses on investments	(96,000,000)	(75,000,000)	(216,000,000)
Impairments of investments	(53,000,000)	(5,000,000)	(10,000,000)
Net gain (loss) on sales of investments	0	67,000,000	(7,000,000)
Gains (losses) on purchases or exchanges of debt	279,000,000	(197,000,000)	(193,000,000)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(19,098,000,000)	3,200,000,000	1,442,000,000
TOTAL ASSETS	17,357,000,000	40,751,000,000	41,782,000,000
Payments to Acquire Productive Assets	3,600,000,000	6,667,000,000	7,190,000,000
Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	693,000,000	(1,394,000,000)	(228,000,000)
Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	(295,000,000)	(3,000,000)
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	5,391,000,000	10,354,000,000	8,626,000,000
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	7,373,000,000	12,225,000,000	9,559,000,000
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	516,000,000	879,000,000
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	30,000,000	16,000,000
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	12,764,000,000	23,125,000,000	19,080,000,000
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	5,391,000,000	10,354,000,000	8,626,000,000
Depreciation, depletion and amortization	2,170,000,000	2,756,000,000	2,674,000,000
Impairment of oil and natural gas properties	18,238,000,000
Impairments of fixed assets and other	126,000,000	22,000,000	27,000,000
Net (gains) losses on sales of fixed assets	1,000,000	(2,000,000)	2,000,000
Interest expense	(925,000,000)	(709,000,000)	(918,000,000)
Losses on investments	(3,000,000)	2,000,000	3,000,000
Impairments of investments	0	0	0
Net gain (loss) on sales of investments		(6,000,000)	0
Gains (losses) on purchases or exchanges of debt	279,000,000	(197,000,000)	(193,000,000)
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(19,619,000,000)	2,874,000,000	2,997,000,000
TOTAL ASSETS	11,819,000,000	35,381,000,000	35,341,000,000
Payments to Acquire Productive Assets	3,562,000,000	6,173,000,000	6,198,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member] | Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	693,000,000	(1,394,000,000)	(228,000,000)
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	11,745,000,000	20,790,000,000	17,129,000,000
Depreciation, depletion and amortization	20,000,000	38,000,000	46,000,000
Impairment of oil and natural gas properties	0
Impairments of fixed assets and other	68,000,000	24,000,000	50,000,000
Net (gains) losses on sales of fixed assets	1,000,000	(187,000,000)	(329,000,000)
Interest expense	(4,000,000)	(21,000,000)	(24,000,000)
Losses on investments	0	0	0
Impairments of investments	0	0	0
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases or exchanges of debt	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	117,000,000	326,000,000	511,000,000
TOTAL ASSETS	1,524,000,000	1,978,000,000	2,430,000,000
Payments to Acquire Productive Assets	42,000,000	298,000,000	299,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member] | Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	(295,000,000)	(3,000,000)
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	1,060,000,000	2,188,000,000
Depreciation, depletion and amortization	0	145,000,000	289,000,000
Impairment of oil and natural gas properties	0
Impairments of fixed assets and other	0	23,000,000	75,000,000
Net (gains) losses on sales of fixed assets	0	(8,000,000)	(1,000,000)
Interest expense	0	(42,000,000)	(82,000,000)
Losses on investments	0	(1,000,000)	0
Impairments of investments	0	(5,000,000)	(1,000,000)
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases or exchanges of debt	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	0	(16,000,000)	(51,000,000)
TOTAL ASSETS	0	0	2,018,000,000
Payments to Acquire Productive Assets	0	158,000,000	272,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member] | Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	30,000,000	29,000,000
Depreciation, depletion and amortization	39,000,000	42,000,000	49,000,000
Impairment of oil and natural gas properties	0
Impairments of fixed assets and other	0	19,000,000	394,000,000
Net (gains) losses on sales of fixed assets	2,000,000	(2,000,000)	26,000,000
Interest expense	(6,000,000)	(3,000,000)	(74,000,000)
Losses on investments	(93,000,000)	(76,000,000)	(219,000,000)
Impairments of investments	(53,000,000)	0	(10,000,000)
Net gain (loss) on sales of investments		73,000,000	(7,000,000)
Gains (losses) on purchases or exchanges of debt	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(127,000,000)	(30,000,000)	(727,000,000)
TOTAL ASSETS	4,325,000,000	4,283,000,000	5,750,000,000
Payments to Acquire Productive Assets	10,000,000	38,000,000	421,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member] | Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest		46,000,000	(1,288,000,000)
Intersegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	(4,372,000,000)	(8,565,000,000)	(7,570,000,000)
Intersegment Eliminations [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	(544,000,000)	(1,309,000,000)
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	(13,000,000)
Intersegment Eliminations [Member] | Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	(4,372,000,000)	(9,109,000,000)	(8,892,000,000)
Depreciation, depletion and amortization	0	(66,000,000)	(155,000,000)
Impairment of oil and natural gas properties	0
Impairments of fixed assets and other	0	0	0
Net (gains) losses on sales of fixed assets	0	0	0
Interest expense	(606,000,000)	680,000,000	871,000,000
Losses on investments	0	0	0
Impairments of investments	0	0	1,000,000
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases or exchanges of debt	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	531,000,000
TOTAL ASSETS	(311,000,000)	(891,000,000)	(3,757,000,000)
Payments to Acquire Productive Assets	0	0	0
Intersegment Eliminations [Member] | Reportable Subsegments [Member] | Commodity [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0	0
Intersegment Eliminations [Member] | Reportable Subsegments [Member] | Marketing [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Derivatives	0	0
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 4,372,000,000	$ 9,109,000,000	$ 8,892,000,000

Major Customers and Segment 132

Major Customers and Segment Information - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Concentration Risk, Percentage			10.00%
Segment Reporting, Disclosure of Major Customers			0
Number of reportable segments | Segment	2
Total Revenues	$ 12,764	$ 23,125	$ 19,080
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	7,373	12,225	9,559
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(4,372)	(8,565)	(7,570)
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	516	879
Oilfield Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ (544)	$ (1,309)
BP PLC [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage	14.00%
ExxonMobil [Member]
Segment Reporting Information [Line Items]
Concentration Risk, Percentage		12.00%

Condensed Consolidating Fina133

Condensed Consolidating Financial Information - Balance Sheet Table (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 825	$ 4,108	$ 837	$ 287
Restricted cash	0	38
Other current assets	160	207
Intercompany receivable, net	0	0
Total Current Assets	2,480	7,468
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	12,089	30,143
Other property and equipment, net	2,114	2,279
Property and equipment held for sale, net	95	93
Total Property and Equipment, Net	14,298	32,515
LONG-TERM ASSETS:
Other long-term assets	197	497
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	17,357	40,751	41,782
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	2,219	3,061
Intercompany payable, net	0	0
Total Current Liabilities	3,685	5,656
LONG-TERM LIABILITIES:
Long-term debt, net	10,354	11,154
Deferred income tax liabilities	0	4,392
Other long-term liabilities	409	679
Total Long-Term Liabilities	11,275	16,890
EQUITY:
Chesapeake stockholders’ equity	2,138	16,903
Noncontrolling interests	259	1,302
Total Equity	2,397	18,205	18,140
TOTAL LIABILITIES AND EQUITY	17,357	40,751
Parent Company Member]
CURRENT ASSETS:
Cash and cash equivalents	928	4,100	799	228
Restricted cash		0
Other current assets	87	55
Intercompany receivable, net	24,789	24,527
Total Current Assets	25,804	28,682
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	74	153
Investments in subsidiaries and intercompany advances	(12,349)	126
TOTAL ASSETS	13,529	28,961
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	921	761
Intercompany payable, net	0	0
Total Current Liabilities	921	761
LONG-TERM LIABILITIES:
Long-term debt, net	10,354	11,154
Deferred income tax liabilities		31
Other long-term liabilities	116	112
Total Long-Term Liabilities	10,470	11,297
EQUITY:
Chesapeake stockholders’ equity	2,138	16,903
Noncontrolling interests	0	0
Total Equity	2,138	16,903
TOTAL LIABILITIES AND EQUITY	13,529	28,961
Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	2	2	8	0
Restricted cash		0
Other current assets	1,561	3,174
Intercompany receivable, net	0	0
Total Current Assets	1,563	3,176
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	11,861	28,358
Other property and equipment, net	2,113	2,276
Property and equipment held for sale, net	95	93
Total Property and Equipment, Net	14,069	30,727
LONG-TERM ASSETS:
Other long-term assets	495	618
Investments in subsidiaries and intercompany advances	771	467
TOTAL ASSETS	16,898	34,988
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	2,862	4,915
Intercompany payable, net	25,580	24,940
Total Current Liabilities	28,442	29,855
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities		3,917
Other long-term liabilities	805	1,090
Total Long-Term Liabilities	805	5,007
EQUITY:
Chesapeake stockholders’ equity	(12,349)	126
Noncontrolling interests	0	0
Total Equity	(12,349)	126
TOTAL LIABILITIES AND EQUITY	16,898	34,988
Non-Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	1	84	38	59
Restricted cash		38
Other current assets	7	93
Intercompany receivable, net	434	341
Total Current Assets	442	556
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	69	1,112
Other property and equipment, net	1	3
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	70	1,115
LONG-TERM ASSETS:
Other long-term assets	10	26
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	522	1,697
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	8	58
Intercompany payable, net	0	0
Total Current Liabilities	8	58
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities		244
Other long-term liabilities	0	142
Total Long-Term Liabilities	0	386
EQUITY:
Chesapeake stockholders’ equity	514	1,253
Noncontrolling interests	0	0
Total Equity	514	1,253
TOTAL LIABILITIES AND EQUITY	522	1,697
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	(106)	(78)	$ (8)	$ 0
Restricted cash		0
Other current assets	0	0
Intercompany receivable, net	(25,223)	(24,868)
Total Current Assets	(25,329)	(24,946)
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	159	673
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	159	673
LONG-TERM ASSETS:
Other long-term assets	0	(29)
Investments in subsidiaries and intercompany advances	11,578	(593)
TOTAL ASSETS	(13,592)	(24,895)
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	(106)	(78)
Intercompany payable, net	(25,580)	(24,940)
Total Current Liabilities	(25,686)	(25,018)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities		200
Other long-term liabilities	0	0
Total Long-Term Liabilities	0	200
EQUITY:
Chesapeake stockholders’ equity	11,835	(1,379)
Noncontrolling interests	259	1,302
Total Equity	12,094	(77)
TOTAL LIABILITIES AND EQUITY	(13,592)	(24,895)
Consolidated Entities [Member]
CURRENT ASSETS:
Other current assets	1,655	3,322
LONG-TERM ASSETS:
Other long-term assets	579	768
CURRENT LIABILITIES:
Other current liabilities ($8 and $15 attributable to our VIE)	3,685	5,656
LONG-TERM LIABILITIES:
Other long-term liabilities	$ 921	$ 1,344

Condensed Consolidating Fina134

Condensed Consolidating Financial Information -Statement Of Operations Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
REVENUES:
Oil, natural gas and NGL	$ 5,391	$ 10,354	$ 8,626
Marketing, gathering and compression	7,373	12,225	9,559
Oilfield services	0	546	895
Total Revenues	12,764	23,125	19,080
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,046	1,208	1,159
Oil, natural gas and NGL gathering, processing and transportation	2,119	2,174	1,574
Production taxes	99	232	229
Marketing, gathering and compression	7,130	12,236	9,461
Oilfield services	0	431	736
General and administrative	235	322	457
Restructuring and other termination costs	36	7	248
Provision for legal contingencies	353	234	0
Oil, natural gas and NGL depreciation, depletion and amortization	2,099	2,683	2,589
Depreciation and amortization of other assets	130	232	314
Impairment of oil and natural gas properties	18,238	0	0
Impairments of fixed assets and other	194	88	546
Net gains (losses) on sales of fixed assets	4	(199)	(302)
Total Operating Expenses	31,683	19,648	17,011
INCOME FROM OPERATIONS	(18,919)	3,477	2,069
OTHER INCOME (EXPENSE):
Interest expense	(317)	(89)	(227)
Losses on investments	(96)	(75)	(216)
Impairments of investments	(53)	(5)	(10)
Net gain (loss) on sales of investments	0	67	(7)
Gains (losses) on purchases of debt	279	(197)	(193)
Other income	8	22	26
Proceeds from Equity Method Investment, Dividends or Distributions	0	0	0
Total Other Expense	(179)	(277)	(627)
INCOME (LOSS) BEFORE INCOME TAXES	(19,098)	3,200	1,442
Total Income Tax Expense (Benefit)	(4,463)	1,144	548
Deferred income taxes	(4,427)	1,097	526
NET INCOME (LOSS)	(14,635)	2,056	894
Net income attributable to noncontrolling interests	(50)	(139)	(170)
Net income (loss) attributable to Chesapeake	(14,685)	1,917	724
Other Comprehensive Income (Loss), Net of Tax	44	19	20
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(14,641)	1,936	744
Parent Company Member]
REVENUES:
Oil, natural gas and NGL	0	0	0
Marketing, gathering and compression	0	0	0
Oilfield services		0	0
Total Revenues	0	0	0
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0
Oil, natural gas and NGL gathering, processing and transportation	0	0	0
Production taxes	0	0	0
Marketing, gathering and compression	0	0	0
Oilfield services		0	0
General and administrative	1	0	0
Restructuring and other termination costs	0	0	0
Provision for legal contingencies	339	100
Oil, natural gas and NGL depreciation, depletion and amortization	0	0	0
Depreciation and amortization of other assets	0	0	0
Impairment of oil and natural gas properties	0	0	0
Impairments of fixed assets and other	0	0	0
Net gains (losses) on sales of fixed assets	0	0	0
Total Operating Expenses	340	100	0
INCOME FROM OPERATIONS	(340)	(100)	0
OTHER INCOME (EXPENSE):
Interest expense	(721)	(657)	(921)
Losses on investments	0	0	0
Impairments of investments	0	0	0
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases of debt	279	(195)	(70)
Other income	140	502	3,979
Proceeds from Equity Method Investment, Dividends or Distributions	(14,197)	2,206	(1,129)
Total Other Expense	(14,499)	1,856	1,859
INCOME (LOSS) BEFORE INCOME TAXES	(14,839)	1,756	1,859
Total Income Tax Expense (Benefit)	(154)	(161)	1,135
NET INCOME (LOSS)	(14,685)	1,917	724
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	(14,685)	1,917	724
Other Comprehensive Income (Loss), Net of Tax	21	1	3
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(14,664)	1,918	727
Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	5,252	9,899	8,013
Marketing, gathering and compression	7,373	12,220	9,547
Oilfield services		41	221
Total Revenues	12,625	22,160	17,781
OPERATING EXPENSES:
Oil, natural gas and NGL production	1,019	1,166	1,112
Oil, natural gas and NGL gathering, processing and transportation	2,094	2,134	1,574
Production taxes	97	227	222
Marketing, gathering and compression	7,129	12,232	9,455
Oilfield services		53	239
General and administrative	231	273	375
Restructuring and other termination costs	36	4	244
Provision for legal contingencies	14	134
Oil, natural gas and NGL depreciation, depletion and amortization	2,051	2,523	2,336
Depreciation and amortization of other assets	130	153	180
Impairment of oil and natural gas properties	18,224	0	(2)
Impairments of fixed assets and other	194	65	417
Net gains (losses) on sales of fixed assets	4	(192)	(301)
Total Operating Expenses	31,223	18,772	15,851
INCOME FROM OPERATIONS	(18,598)	3,388	1,930
OTHER INCOME (EXPENSE):
Interest expense	(198)	(37)	(4)
Losses on investments	(96)	(77)	(216)
Impairments of investments	(53)	0	(9)
Net gain (loss) on sales of investments		67	(7)
Gains (losses) on purchases of debt	0	(2)	(123)
Other income	10	198	(603)
Proceeds from Equity Method Investment, Dividends or Distributions	(402)	(258)	(383)
Total Other Expense	(739)	(109)	(1,345)
INCOME (LOSS) BEFORE INCOME TAXES	(19,337)	3,279	585
Total Income Tax Expense (Benefit)	(4,421)	1,264	369
NET INCOME (LOSS)	(14,916)	2,015	216
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	(14,916)	2,015	216
Other Comprehensive Income (Loss), Net of Tax	23	18	19
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(14,893)	2,033	235
Non-Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	139	458	553
Marketing, gathering and compression	0	5	12
Oilfield services		983	1,836
Total Revenues	139	1,446	2,401
OPERATING EXPENSES:
Oil, natural gas and NGL production	27	42	47
Oil, natural gas and NGL gathering, processing and transportation	25	40	0
Production taxes	2	5	7
Marketing, gathering and compression	1	4	6
Oilfield services		769	1,434
General and administrative	3	49	83
Restructuring and other termination costs	0	3	4
Provision for legal contingencies	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	69	162	253
Depreciation and amortization of other assets	0	143	281
Impairment of oil and natural gas properties	472	349	313
Impairments of fixed assets and other	0	23	129
Net gains (losses) on sales of fixed assets	0	(7)	(1)
Total Operating Expenses	599	1,582	2,556
INCOME FROM OPERATIONS	(460)	(136)	(155)
OTHER INCOME (EXPENSE):
Interest expense	0	(42)	(85)
Losses on investments	0	0	0
Impairments of investments	0	(5)	(1)
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases of debt	0	0	0
Other income	1	(2)	13
Proceeds from Equity Method Investment, Dividends or Distributions	0	0	0
Total Other Expense	1	(49)	(73)
INCOME (LOSS) BEFORE INCOME TAXES	(459)	(185)	(228)
Total Income Tax Expense (Benefit)	(107)	(66)	(87)
NET INCOME (LOSS)	(352)	(119)	(141)
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	(352)	(119)	(141)
Other Comprehensive Income (Loss), Net of Tax	0	0	(2)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(352)	(119)	(143)
Eliminations [Member]
REVENUES:
Oil, natural gas and NGL	0	(3)	60
Marketing, gathering and compression	0	0	0
Oilfield services		(478)	(1,162)
Total Revenues	0	(481)	(1,102)
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0
Oil, natural gas and NGL gathering, processing and transportation	0	0	0
Production taxes	0	0	0
Marketing, gathering and compression	0	0	0
Oilfield services		(391)	(937)
General and administrative	0	0	(1)
Restructuring and other termination costs	0	0	0
Provision for legal contingencies	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	(21)	(2)	0
Depreciation and amortization of other assets	0	(64)	(147)
Impairment of oil and natural gas properties	(458)	(349)	(311)
Impairments of fixed assets and other	0	0	0
Net gains (losses) on sales of fixed assets	0	0	0
Total Operating Expenses	(479)	(806)	(1,396)
INCOME FROM OPERATIONS	479	325	294
OTHER INCOME (EXPENSE):
Interest expense	602	647	783
Losses on investments	0	2	0
Impairments of investments	0	0	0
Net gain (loss) on sales of investments		0	0
Gains (losses) on purchases of debt	0	0	0
Other income	(143)	(676)	(3,363)
Proceeds from Equity Method Investment, Dividends or Distributions	14,599	(1,948)	1,512
Total Other Expense	15,058	(1,975)	(1,068)
INCOME (LOSS) BEFORE INCOME TAXES	15,537	(1,650)	(774)
Total Income Tax Expense (Benefit)	219	107	(869)
NET INCOME (LOSS)	15,318	(1,757)	95
Net income attributable to noncontrolling interests	(50)	(139)	(170)
Net income (loss) attributable to Chesapeake	15,268	(1,896)	(75)
Other Comprehensive Income (Loss), Net of Tax	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ 15,268	$ (1,896)	$ (75)

Condensed Consolidating Fina135

Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flows From Operating Activities
Net Cash Provided By Operating Activities	$ 1,234	$ 4,634	$ 4,614
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(3,095)	(4,581)	(5,604)
Acquisitions of proved and unproved properties	(533)	(1,311)	(1,032)
Proceeds from divestitures of proved and unproved properties	189	5,813	3,467
Additions to other property and equipment	(143)	(726)	(972)
Other investing activities	0	(3)	4
Net Cash Used In Investing Activities	(3,451)	454	(2,967)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	7,406	7,669
Payments on credit facilities borrowings	0	(7,788)	(7,682)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	394	0
Cash paid to purchase debt	(508)	(3,362)	(2,141)
Proceeds from sales of noncontrolling interests	0	0	6
Other financing activities	(41)	(34)	(105)
Intercompany advances, net	0	0	0
Net Cash Provided By (Used) In Financing Activities	(1,066)	(1,817)	(1,097)
Net increase (decrease) in cash and cash equivalents	(3,283)	3,271	550
Cash and cash equivalents, beginning of period	4,108	837	287
Cash and cash equivalents, end of period	825	4,108	837
Parent Company Member]
Cash Flows From Operating Activities
Net Cash Provided By Operating Activities	0	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other investing activities	0	0	0
Net Cash Used In Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		0	0
Payments on credit facilities borrowings		0	0
Proceeds from issuance of senior notes, net of discount and offering costs		2,966	2,274
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Cash paid to purchase debt	(508)	(3,362)	(2,141)
Proceeds from sales of noncontrolling interests			0
Other financing activities	(789)	(439)	1,819
Intercompany advances, net	(1,875)	4,136	(1,381)
Net Cash Provided By (Used) In Financing Activities	(3,172)	3,301	571
Net increase (decrease) in cash and cash equivalents	(3,172)	3,301	571
Cash and cash equivalents, beginning of period	4,100	799	228
Cash and cash equivalents, end of period	928	4,100	799
Guarantor Subsidiaries [Member]
Cash Flows From Operating Activities
Net Cash Provided By Operating Activities	1,142	4,201	4,218
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(3,032)	(4,445)	(4,838)
Acquisitions of proved and unproved properties	(529)	(1,306)	(1,378)
Proceeds from divestitures of proved and unproved properties	152	5,812	3,466
Additions to other property and equipment	(148)	(480)	(271)
Other investing activities	67	1,199	246
Net Cash Used In Investing Activities	(3,490)	780	(2,775)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		6,689	6,452
Payments on credit facilities borrowings		(6,689)	(6,452)
Proceeds from issuance of senior notes, net of discount and offering costs		0	0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests			0
Other financing activities	473	(1,278)	(2,897)
Intercompany advances, net	1,875	(3,709)	1,462
Net Cash Provided By (Used) In Financing Activities	2,348	(4,987)	(1,435)
Net increase (decrease) in cash and cash equivalents	0	(6)	8
Cash and cash equivalents, beginning of period	2	8	0
Cash and cash equivalents, end of period	2	2	8
Non-Guarantor Subsidiaries [Member]
Cash Flows From Operating Activities
Net Cash Provided By Operating Activities	110	462	439
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(63)	(136)	(766)
Acquisitions of proved and unproved properties	(4)	(5)	346
Proceeds from divestitures of proved and unproved properties	37	1	1
Additions to other property and equipment	5	(246)	(701)
Other investing activities	52	60	765
Net Cash Used In Investing Activities	27	(326)	(355)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	(143)
Proceeds from credit facilities borrowings		717	1,217
Payments on credit facilities borrowings		(1,099)	(1,230)
Proceeds from issuance of senior notes, net of discount and offering costs		494	0
Proceeds from issuance of oilfield services term loan, net of issuance costs		394
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests			6
Other financing activities	(77)	(169)	(17)
Intercompany advances, net	0	(427)	(81)
Net Cash Provided By (Used) In Financing Activities	(220)	(90)	(105)
Net increase (decrease) in cash and cash equivalents	(83)	46	(21)
Cash and cash equivalents, beginning of period	84	38	59
Cash and cash equivalents, end of period	1	84	38
Eliminations [Member]
Cash Flows From Operating Activities
Net Cash Provided By Operating Activities	(18)	(29)	(43)
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0	0
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other investing activities	12	0	163
Net Cash Used In Investing Activities	12	0	163
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		0	0
Payments on credit facilities borrowings		0	0
Proceeds from issuance of senior notes, net of discount and offering costs		0	0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Cash paid to purchase debt	0	0	0
Proceeds from sales of noncontrolling interests			0
Other financing activities	(22)	(41)	(128)
Intercompany advances, net	0	0	0
Net Cash Provided By (Used) In Financing Activities	(22)	(41)	(128)
Net increase (decrease) in cash and cash equivalents	(28)	(70)	(8)
Cash and cash equivalents, beginning of period	(78)	(8)	0
Cash and cash equivalents, end of period	(106)	(78)	(8)
Noncontrolling Interest, Chesapeake Cleveland Tonkawa Limited Liability Company [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	(143)	0	0
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	0	2,966	2,274
Consolidated Entities [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Other investing activities	131	1,259	1,174
CASH FLOWS FROM FINANCING ACTIVITIES:
Other financing activities	$ (415)	$ (1,927)	$ (1,223)

Condensed Consolidating Fina136

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%

Subsequent Events Subsequent Ev

Subsequent Events Subsequent Events - Narrative (Details) - USD ($) $ in Millions	Feb. 24, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Subsequent Event [Line Items]
Proceeds from divestitures of proved and unproved properties		$ 189	$ 5,813	$ 3,467
3.25% Senior Notes due 2016 [Member]
Subsequent Event [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.25%
Convertible Debt [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Subsequent Event [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.50%
Senior Notes [Member]
Subsequent Event [Line Items]
Debt Instrument, Repurchase Amount				$ 405
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Subsequent Event [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.50%
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount		$ 119
Debt Instrument, Interest Rate, Stated Percentage		3.25%		3.25%
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Subsequent Event [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.50%
Subsequent Event [Member]
Subsequent Event [Line Items]
Proceeds from divestitures of proved and unproved properties	$ 138
Subsequent Event [Member] | Scenario, Forecast [Member]
Subsequent Event [Line Items]
Proceeds from divestitures of proved and unproved properties	586
Subsequent Event [Member] | Convertible Debt [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount	$ 60
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument, Repurchase Amount	$ 32
Subsequent Event [Member] | Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount	$ 122
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument, Repurchase Amount	$ 115
Subsequent Event [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Subsequent Event [Line Items]
Debt Instrument, Repurchased Face Amount	$ 2
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Repurchase Amount	$ 1