Expand Energy (EXE) 10-Q 5 May 16 2016 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 27, 2016
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q1
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		684,606,831

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 16	$ 825
Accounts receivable, net	937	1,129
Short-term derivative assets	350	366
Other current assets	189	160
Total Current Assets	1,492	2,480
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)	64,305	63,843
Unproved properties	6,612	6,798
Other property and equipment	2,749	2,927
Total Property and Equipment, at Cost	73,666	73,568
Less: accumulated depreciation, depletion and amortization (($445) and ($428) attributable to our VIE)	(60,506)	(59,365)
Property and equipment held for sale, net	131	95
Total Property and Equipment, Net	13,291	14,298
LONG-TERM ASSETS:
Long-term derivative assets	263	246
Other long-term assets	311	290
TOTAL ASSETS	15,357	17,314
CURRENT LIABILITIES:
Accounts payable	723	944
Current maturities of long-term debt, net	343	381
Accrued interest	137	101
Short-term derivative liabilities	86	40
Other current liabilities ($2 and $8 attributable to our VIE)	1,544	2,219
Total Current Liabilities	2,833	3,685
LONG-TERM LIABILITIES:
Long-term debt, net	10,062	10,311
Long-term derivative liabilities	12	60
Asset retirement obligations, net of current portion	453	452
Other long-term liabilities	426	409
Total Long-Term Liabilities	10,953	11,232
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,225,713 and 7,251,515 shares outstanding	3,036	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 684,560,678 and 664,795,509 shares issued	7	7
Additional paid-in capital	12,521	12,403
Accumulated deficit	(14,123)	(13,202)
Accumulated other comprehensive loss	(99)	(99)
Less: treasury stock, at cost; 1,384,506 and 1,437,724 common shares	(31)	(33)
Total Chesapeake Stockholders’ Equity	1,311	2,138
Noncontrolling interests	260	259
Total Equity	1,571	2,397
TOTAL LIABILITIES AND EQUITY	$ 15,357	$ 17,314

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
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)	7,225,713	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	684,560,678	664,795,509
Treasury stock, shares	1,384,506	1,437,724
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 16	$ 825
VIE. proved natural gas and oil properties	64,305	63,843
VIE. accumulated depreciation, depletion and amortization	(60,506)	(59,365)
VIE. other current liabilities	1,544	2,219
Variable Interest Entities, Primary Beneficiary [Member]
Cash and cash equivalents ($1 and $1 attributable to our VIE)	1	1
VIE. proved natural gas and oil properties	488	488
VIE. accumulated depreciation, depletion and amortization	(445)	(428)
VIE. other current liabilities	$ 2	$ 8

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Oil, natural gas and NGL	$ 993	$ 1,543
Marketing, gathering and compression	960	1,675
Total Revenues	1,953	3,218
OPERATING EXPENSES:
Oil, natural gas and NGL production	206	299
Oil, natural gas and NGL gathering, processing and transportation	482	458
Production taxes	18	28
Marketing, gathering and compression	942	1,700
General and administrative	48	56
Restructuring and other termination costs	0	(10)
Provision for legal contingencies	22	25
Oil, natural gas and NGL depreciation, depletion and amortization	271	684
Depreciation and amortization of other assets	29	35
Impairment of oil and natural gas properties	853	4,976
Impairments of fixed assets and other	38	4
Net (gains) losses on sales of fixed assets	(4)	3
Total Operating Expenses	2,905	8,258
LOSS FROM OPERATIONS	(952)	(5,040)
OTHER INCOME (EXPENSE):
Interest expense	(62)	(51)
Losses on investments	0	(7)
Loss on sale of investment	(10)	0
Gains on purchases or exchanges of debt	100	0
Other income	3	6
Total Other Income (Expense)	31	(52)
LOSS BEFORE INCOME TAXES	(921)	(5,092)
INCOME TAX BENEFIT:
Current income taxes	0	0
Deferred income taxes	0	(1,372)
Total Income Tax Benefit	0	(1,372)
NET LOSS	(921)	(3,720)
Net income attributable to noncontrolling interests	0	(19)
NET LOSS ATTRIBUTABLE TO CHESAPEAKE	(921)	(3,739)
Preferred stock dividends	(43)	(43)
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS	$ (964)	$ (3,782)
LOSS PER COMMON SHARE:
Earnings Per Share, Basic	$ (1.44)	$ (5.72)
Earnings Per Share, Diluted	(1.44)	(5.72)
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0	$ 0.0875
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	668	661
Weighted Average Number of Shares Outstanding, Diluted	668	661

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
NET LOSS	$ (921)	$ (3,720)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($3) and ($1)	(4)	(1)
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $7 and $7	4	10
Other Comprehensive Income	0	9
COMPREHENSIVE LOSS	(921)	(3,711)
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	0	(19)
COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE	$ (921)	$ (3,730)

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of ($3) and ($1)	$ (3)	$ (1)
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $7 and $7	$ 7	$ 7

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET LOSS	$ (921)	$ (3,720)
ADJUSTMENTS TO RECONCILE NET LOSS TO CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES:
Depreciation, depletion and amortization	300	719
Deferred income tax expense (benefit)	0	(1,372)
Derivative gains, net	(201)	(172)
Cash receipts on derivative settlements, net	267	408
Stock-based compensation	12	23
Impairment of oil and natural gas properties	853	4,976
Net (gains) losses on sales of fixed assets	(4)	3
Impairments of fixed assets and other	33	2
Losses on investments	0	7
Loss on sale of investment	10	0
Gains on purchases or exchanges of debt	(100)	0
Restructuring and other termination costs	0	(10)
Provision for legal contingencies	22	25
Other	(8)	(7)
Changes in assets and liabilities	(684)	(459)
Net Cash Provided By (Used In) Operating Activities	(421)	423
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(265)	(1,306)
Acquisitions of proved and unproved properties	(67)	(128)
Proceeds from divestitures of proved and unproved properties	62	21
Additions to other property and equipment	(10)	(58)
Proceeds from sales of other property and equipment	9	2
Additions to investments	0	(1)
Other	(2)	(2)
Net Cash Used In Investing Activities	(273)	(1,472)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to purchase debt	(472)	0
Proceeds from credit facilities borrowings	515	0
Payments on credit facilities borrowings	(148)	0
Cash paid for common stock dividends	0	(59)
Cash paid for preferred stock dividends	0	(43)
Distributions to noncontrolling interest owners	(5)	(29)
Other	(5)	(21)
Net Cash Used In Financing Activities	(115)	(152)
Net decrease in cash and cash equivalents	(809)	(1,201)
Cash and cash equivalents, beginning of period	825	4,108
Cash and cash equivalents, end of period	16	2,907
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	39	43
Income taxes paid, net of refunds received	(19)	47
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	(9)	63
Change in divested proved and unproved properties	0	(53)
Debt exchanged for common stock	$ 77	$ 0

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Convertible Note Exchange [Member]	Additional Paid-in Capital [Member]Senior Note Exhange [Member]	Additional Paid-in Capital [Member]Convertible Preferred Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2014		$ 3,062		$ 12,531				$ 1,483	$ (143)	$ (37)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				12
Conversions/exchanges during period, value		0			$ 0	$ 0	$ 0
Dividends on common stock				(59)
Dividends on preferred stock				(43)
Decrease in tax benefit from stock-based compensation				(5)
Net loss attributable to Chesapeake	$ (3,739)
Hedging activity									9
Purchase of 10,100 and 12,401 shares for company benefit plans										0
Release of 63,318 and 41,046 shares from company benefit plans										0
Chesapeake stockholders’ equity, end of period at Mar. 31, 2015		3,062	$ 7	12,436				(2,256)	(134)	(37)	$ 13,078
Stockholders' Equity Attributable to Noncontrolling Interest, Beginning of Period at Dec. 31, 2014												$ 1,302
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	19
Distributions to noncontrolling interest owners												(26)
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Mar. 31, 2015												1,295
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	14,373
TOTAL EQUITY	2,397
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2015	2,138	3,062		12,403				(13,202)	(99)	(33)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				16
Conversions/exchanges during period, value		26			$ 65	$ 11	$ 26
Dividends on common stock				0
Dividends on preferred stock				0
Decrease in tax benefit from stock-based compensation				0
Net loss attributable to Chesapeake	(921)
Hedging activity									0
Purchase of 10,100 and 12,401 shares for company benefit plans										0
Release of 63,318 and 41,046 shares from company benefit plans										2
Chesapeake stockholders’ equity, end of period at Mar. 31, 2016	1,311	$ 3,036	$ 7	$ 12,521				$ (14,123)	$ (99)	$ (31)	$ 1,311
Stockholders' Equity Attributable to Noncontrolling Interest, Beginning of Period at Dec. 31, 2015	259											259
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	0
Distributions to noncontrolling interest owners												1
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Mar. 31, 2016	260											$ 260
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	$ 1,571

CONDENSED CONSOLIDATED STATEME9

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Preferred Stock [Member]
Conversion of Stock, Shares Converted	25,802	0
Treasury Stock - Common [Member]
Purchase of shares for company benefit plans, shares	10,100	12,401
Release of shares from company benefit plans, shares	63,318	41,046
Convertible Note Exchange [Member]
Stock Issued During Period, Shares, Conversion of Convertible Securities	14,699,000	0
Senior Note Exhange [Member]
Stock Issued During Period, Shares, Conversion of Convertible Securities	2,556,000	0
Preferred Stock Exchange [Member]
Stock Issued During Period, Shares, Conversion of Convertible Securities	1,022,000	0

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies (Note)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies Disclosure	Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation ("Chesapeake" or the "Company") and its subsidiaries 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. These financial statements were prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP. This Form 10-Q relates to the three months ended March 31, 2016 (the "Current Quarter") and the three months ended March 31, 2015 (the "Prior Quarter"). Chesapeake's annual report on Form 10-K for the year ended December 31, 2015 ("2015 Form 10-K") includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair statement of the results for the interim periods have been reflected. The results for the Current Quarter are not necessarily indicative of the results to be expected for the full year. 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 natural gas liquids (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 substantial decline in oil, natural gas and NGL prices from 2014 levels has negatively affected the amount of cash we have available for capital expenditures and debt service. In the Current Quarter, 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 $853 million , which was the primary driver of our net loss in the Current Quarter of $921 million . Based on the first-day-of-the-month prices we have received over the 11 months ended May 1, 2016 , as well as the current strip price for June 2016, we expect to record downward reserve revisions and another material write-down in the carrying value of our oil and natural gas properties in the second 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 March 31, 2016 , we had a cash balance of approximately $16 million compared to $825 million as of December 31, 2015, and we had a net working capital deficit of approximately $1.341 billion compared to a net working capital deficit of approximately $1.205 billion as of December 31, 2015. 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 the next 12 months. Oil, natural gas and NGL prices have a material impact on our financial position, results of operations, cash flows and quantities of 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, our ability to comply with the financial covenants under our revolving credit facility and make scheduled debt payments could be adversely impacted. In April 2016, we further amended our revolving credit facility agreement. Pursuant to the amendment, our borrowing base was reaffirmed in the amount of $4.0 billion and our next scheduled borrowing base redetermination date was postponed until June 15, 2017, with the consenting lenders agreeing not to exercise their interim redetermination right prior to that date. The amendment also modifies the credit agreement to provide for, among other things, (i) the suspension or modification of certain financial covenants and (ii) the granting of liens and security interests on substantially all of our assets, including mortgages encumbering 90% of our proved oil and gas properties that constitute borrowing base properties, all hedge contracts and personal property, subject to certain agreed upon carve outs . See Note 3 for further discussion of our revolving credit facility. As of March 31, 2016 , we had approximately $9.425 billion principal amount of debt outstanding, of which $1.625 billion matures or can be put to us in 2017 (including $344 million of maturities in January 2017, $902 million which can be put to us in May 2017 and $379 million that matures in August 2017) and $878 million that 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. As of March 31, 2016 , we had $367 million of outstanding borrowings under our revolving credit facility. 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 flows 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 the remainder of 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 gathering, processing, transportation and hedging agreements. As of May 3 , 2016, we have received requests to post approximately $281 million in collateral under such arrangements, of which we have posted approximately $247 million (excluding the supersedeas bond with respect to the 6.775% Senior Notes due 2019 (the 2019 Notes) litigation discussed in Note 4). 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 $696 million , which may be in the form of additional letters of credit, cash or other acceptable collateral. However, we have substantial long-term business relationships with each of these counterparties, and we may be able to mitigate any collateral requests through ongoing business arrangements 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. 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 the remainder of 2016. We have taken measures to mitigate the risks and uncertainties facing us for the next 12 months, including mitigating a portion of our downside exposure to lower commodity prices through derivative contracts, the suspension of payment of dividends on our convertible preferred stock and the April 2016 amendment to our revolving credit facility; however, there can be no assurance that these measures 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 decrease, 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. Reclassifications In April 2015, the Financial Accounting Standards Board (FASB) issued guidance that requires debt issuance costs to be presented in the balance sheet as a direct deduction from the associated debt liability. This standard requires retrospective application and is effective for annual reporting periods beginning after December 15, 2015. This change in accounting principle is preferable since it allows debt issuance costs and debt issuance discounts to be presented similarly in the consolidated balance sheets as a reduction to the face amount of our debt balances. A retrospective change to our consolidated balance sheet as of December 31, 2015, as previously presented, is required pursuant to the guidance. The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below. As Previously Reported December 31, 2015 Adjustment Effect As Adjusted $ in millions Other long-term assets $ 333 $ (43 ) $ 290 Long-term debt, net $ 10,354 $ 43 $ 10,311 Beginning in the fourth quarter of 2015, we began presenting third party transportation and gathering costs as a component of operating expenses in the statement of operations. Previously, these costs were reflected as deductions to oil, natural gas and NGL sales. These costs have been reclassified in our condensed consolidated statement of operations for the Prior Quarter to conform to the presentation used for the Current Quarter. The net effect of this reclassification did not impact our previously reported net loss, 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.

Earnings Per Share (Note)

Earnings Per Share (Note)	3 Months Ended
	Mar. 31, 2016
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 Current Quarter and the Prior Quarter, 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 Current Quarter and the Prior Quarter, 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) Three Months Ended March 31, 2016 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 21 58 5.75% cumulative convertible preferred stock (series A) $ 16 42 5.00% cumulative convertible preferred stock (series 2005B) $ 3 6 4.50% cumulative convertible preferred stock $ 3 6 Participating securities $ — 1 Three Months Ended March 31, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 21 59 5.75% cumulative convertible preferred stock (series A) $ 16 42 5.00% cumulative convertible preferred stock (series 2005B) $ 3 6 4.50% cumulative convertible preferred stock $ 3 6 Participating securities $ — 2

Debt (Note)

Debt (Note)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Debt Disclosure	Debt Our long-term debt consisted of the following as of March 31, 2016 and December 31, 2015: March 31, 2016 December 31, 2015 Principal Amount Carrying Principal Carrying ($ in millions) 3.25% senior notes due 2016 $ — $ — $ 381 381 6.25% euro-denominated senior notes due 2017 (a) 344 344 329 329 6.5% senior notes due 2017 379 379 453 453 7.25% senior notes due 2018 538 538 538 538 Floating rate senior notes due 2019 1,104 1,104 1,104 1,104 6.625% senior notes due 2020 822 822 822 822 6.875% senior notes due 2020 304 304 304 304 6.125% senior notes due 2021 589 589 589 589 5.375% senior notes due 2021 286 286 286 286 4.875% senior notes due 2022 639 639 639 639 8.00% senior secured second lien notes due 2022 2,425 3,542 2,425 3,584 5.75% senior notes due 2023 384 384 384 384 2.75% contingent convertible senior notes due 2035 (b) 2 2 2 2 2.5% contingent convertible senior notes due 2037 (b)(c) 902 846 1,110 1,027 2.25% contingent convertible senior notes due 2038 (b)(c) 340 293 340 290 Revolving credit facility 367 367 — — Debt issuance costs — (38 ) — (43 ) Discount on senior notes — (3 ) — (4 ) Interest rate derivatives (d) — 7 — 7 Total debt, net 9,425 10,405 9,706 10,692 Less current maturities of long-term debt, net (e) (344 ) (343 ) (381 ) (381 ) Total long-term debt, net $ 9,081 $ 10,062 $ 9,325 $ 10,311 ___________________________________________ (a) The principal and carrying amounts shown are based on the exchange rate of $1.1380 to €1.00 and $1.0862 to €1.00 as of March 31, 2016 and December 31, 2015, respectively. See Foreign Currency Derivatives in Note 8 for information on our related foreign currency derivatives. (b) 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 Current Quarter, 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 second 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 Current Quarter and the Prior Quarter. 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. We may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time. (c) Discount as of March 31, 2016 and December 31, 2015 included $103 million and $133 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (d) See Interest Rate Derivatives in Note 8 for further discussion related to these instruments. (e) As of March 31, 2016 , current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due 2017. Chesapeake Senior Notes and Contingent Convertible Senior Notes In the Current Quarter, in addition to the repayment upon maturity of $259 million principal amount of our 3.25% Senior Notes due 2016 (together with $122 million principal amount repurchased in the open market for $115 million prior to maturity), we repurchased in the open market approximately $118 million principal amount of our outstanding 2.5% Contingent Convertible Senior Notes due 2037 (that could have been put to us in May 2017) for $63 million and $59 million principal amount of our outstanding 6.5% Senior Notes due 2017 for $36 million . Additionally, we privately negotiated an exchange of approximately $90 million principal amount of our outstanding 2.5% Contingent Convertible Senior Notes due 2037 for 14,699,368 common shares and $15 million principal amount of our outstanding 6.5% Senior Notes due 2017 for 2,555,979 common shares. We recorded an aggregate gain of approximately $100 million associated with the repurchases and exchanges. Revolving Credit Facility We have a $4.0 billion senior secured revolving credit facility that matures in December 2019. As of March 31, 2016 , we had outstanding borrowings of $367 million under the credit facility and had used $619 million of the credit facility for various letters of credit (including the $461 million supersedeas bond with respect to the 2019 Notes litigation discussed in Note 4). 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. We were in compliance with all financial covenants under the agreement as of March 31, 2016. In April 2016, we entered into the third amendment to our senior revolving credit facility. Pursuant to the amendment, our borrowing base was reaffirmed in the amount of $4.0 billion and the next scheduled borrowing base redetermination review was postponed until June 15, 2017, with the consenting lenders agreeing not to exercise their interim redetermination right prior to that date. The amendment also provides temporary financial covenant relief, with the credit facility’s existing first lien secured leverage ratio and net debt to capitalization ratio suspended until September 30, 2017 and the interest coverage ratio maintenance covenant was reduced as noted below. In addition, we agreed to grant liens and security interests on substantially all of our assets, as well as maintain a minimum liquidity amount (defined as cash and cash equivalents and availability under our revolving credit facility) of $500 million until the suspension of the existing maintenance covenants ends. The amendment reduces the interest coverage ratio from 1.1 to 1.0 to 0.65 to 1.0 through the first quarter of 2017, after which it will increase to 0.70 to 1.0 through the second quarter of 2017, 1.2 to 1.0 through the third quarter of 2017 and 1.25 to 1.0 thereafter. The amendment also includes a collateral value coverage test whereby if the collateral value coverage ratio, tested as of December 31, 2016, falls below 1.1 to 1.0, the $500 million minimum liquidity covenant increases to $750 million, and if the collateral value coverage ratio, tested as of March 31, 2017, falls below 1.25 to 1.0, our borrowing ability will be reduced in order to satisfy such ratio. The amendment also gives us the ability to incur up to $2.5 billion of first lien indebtedness secured on a pari passu basis with the existing obligations under the credit agreement, subject to payment priority in favor of the existing lenders and the other limitations on junior lien debt set forth in the credit agreement. Fair Value of Debt We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, including borrowings under our revolving credit facility, is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. March 31, 2016 December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 343 $ 250 $ 381 $ 366 Long-term debt (Level 1) $ 9,688 $ 4,029 $ 10,347 $ 3,735 Long-term debt (Level 2) $ 367 $ 250 $ — $ —

Contingencies and Commitments (

Contingencies and Commitments (Note)	3 Months Ended
	Mar. 31, 2016
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. 2016 Shareholder Litigation . On April 19, 2016, a derivative action was filed in the U.S. District Court for the Western District of Oklahoma against the Company and current and former directors and officers of the Company alleging, among other things, violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act, breach of fiduciary duties, waste of corporate assets, gross mismanagement and violations of Sections 10(b) and Rule 10b-5 of the Exchange Act related to actions allegedly taken by such persons since 2008. The lawsuit seeks certification as a class action, damages, attorneys’ fees and other costs. 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 . As previously disclosed in the 2015 Form 10-K, in connection with the litigation related to the Company’s notice issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes, the Company filed a notice of appeal on July 27, 2015 of an amended judgment entered on July 17, 2015 by the U.S. District Court for the Southern District of New York awarding the Trustee for the 2019 Notes $380 million plus prejudgment interest in the amount of $59 million . The Company posted a supersedeas bond in the amount of $461 million (reflected as an outstanding letter of credit under the Company’s credit facility) to stay execution of the judgment while appellate proceedings are pending. We accrued a loss contingency of $100 million for this matter in 2014, and we accrued an additional $339 million in 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 consolidated 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, Louisiana, Oklahoma 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. The parties subsequently agreed to transfer such other lawsuits to Tarrant County, with Chesapeake reserving the right to request transfer of any other such lawsuits to Harris 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. We expect 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. Chesapeake filed preliminary objections to the amended complaint on April 13, 2016. 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. In March 2016, three putative class action lawsuits were filed in the United States District Court for the Western District of Oklahoma against the Company and other defendants. The lawsuits allege that, since December 2007, and continuing through March 2012, the defendants conspired to rig bids and depress the market for the purchases of oil and natural gas leasehold interests and properties in the Anadarko Basin containing producing oil and natural gas wells, in violation of the Sherman Antitrust Act. The lawsuits seek damages, attorney’s fees, costs and interest, as well as enjoinment from adopting practices or plans which would restrain competition in a similar manner as alleged in the lawsuits. In April 2016, a class action lawsuit on behalf of holders of the Company’s 6.875% Senior Notes due 2020 (2020 Notes) and 6.125% Senior Notes due 2021 (2021 Notes) was filed in the U.S. District Court for the Southern District of New York relating to the Company’s December 2015 debt exchange, whereby the Company privately exchanged newly issued 8.00% Senior Secured Second Lien Notes due 2022 (Second Lien Notes) for certain outstanding senior unsecured notes and contingent convertible notes. The lawsuit alleges that the Company violated the Trust Indenture Act of 1939 and the implied covenant of good faith and fair dealing by benefiting themselves and a minority of noteholders who are qualified institutional buyers (QIBs). According to the lawsuit, as a result of the Company’s private debt exchange in which only QIBs (and non-U.S. persons under Regulation S) were eligible to participate, the Company unjustly enriched itself at the expense of class members by reducing indebtedness and reducing the value of the 2020 Notes and 2022 Notes. The lawsuit seeks damages and attorney’s fees, in addition to declaratory relief that the debt exchange and the liens created for the benefit of the Second Lien Notes are null and void and that the debt exchange effectively resulted in a default under the indentures for the 2020 Notes and 2021 Notes. 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, programs, 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 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 condensed consolidated balance sheets; however, they are reflected as adjustments to oil, natural gas and NGL sales prices used 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. March 31, ($ in millions) 2016 $ 1,383 2017 1,880 2018 1,676 2019 1,378 2020 1,051 2021 – 2099 6,696 Total $ 14,064 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 condensed consolidated balance sheets. As of March 31, 2016 , the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $218 million . Pressure Pumping Contracts We have an agreement for pressure pumping services. Throughout the term of the agreement, which expires in June 2017, the services agreement requires us to utilize, at market-based pricing, the lesser of (i) five pressure pumping crews through June 30, 2016 and three pressure pumping crews through June 30, 2017 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 the 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 the contractor fails to provide the overall quality of service provided by similar service providers. As of March 31, 2016 , the aggregate undiscounted minimum future payments under this agreement were approximately $161 million . Drilling Commitments We have committed to drill wells for the benefit of Chesapeake Granite Wash Trust (the Trust). 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 March 31, 2016 , 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 . We anticipate that we will fulfill our drilling obligation on or before June 30, 2016. See Note 10 for further discussion of the Trust. 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 9 for further discussion of our VPP transactions. Net Acreage Maintenance Commitments Under the terms of our Utica Shale joint venture agreements with Total S.A., 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 a future measurement date. 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 acquisitions and 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 9 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)	3 Months Ended
	Mar. 31, 2016
Other Liabilities Disclosure [Abstract]
Other Liabilities Disclosure	Other Liabilities Other current liabilities as of March 31, 2016 and December 31, 2015 are detailed below. March 31, December 31, ($ in millions) Revenues and royalties due others $ 378 $ 500 Accrued drilling and production costs 216 212 Joint interest prepayments received 103 169 Accrued compensation and benefits 151 264 Other accrued taxes 57 37 Bank of New York Mellon legal accrual 439 439 Minimum gathering volume commitment 4 201 Other 196 397 Total other current liabilities $ 1,544 $ 2,219 Other long-term liabilities as of March 31, 2016 and December 31, 2015 are detailed below. March 31, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 183 $ 190 Financing obligations 29 29 Unrecognized tax benefits 68 64 Other 146 126 Total other long-term liabilities $ 426 $ 409 ____________________________________________ (a) The CHK Utica, L.L.C. investors’ right to receive, proportionately, a 3% overriding royalty interest (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. The liability represents the obligation to deliver future ORRIs. Approximately $25 million and $21 million of the total $208 million and $211 million obligations are recorded in other current liabilities as of March 31, 2016 and December 31, 2015, respectively.

Equity (Note)

Equity (Note)	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Stockholders' Equity Note Disclosure	Equity Common Stock The following is a summary of the changes in our common shares issued for the Current Quarter and the Prior Quarter: Three Months Ended 2016 2015 (in thousands) Shares issued as of January 1 664,796 664,944 Exchange of convertible notes 14,699 — Exchange of senior notes 2,556 — Conversion of preferred stock 1,022 — Restricted stock issuances (net of forfeitures and cancellations) 1,488 151 Stock option exercises — 14 Shares issued as of March 31 684,561 665,109 Preferred Stock Outstanding shares of our preferred stock for the Current Quarter and the Prior Quarter are detailed below. 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2016 1,497 1,100 2,559 2,096 Preferred stock conversions (a) (25 ) (1 ) — — Shares outstanding as of March 31, 2016 1,472 1,099 2,559 2,096 Shares outstanding as of January 1, 2015 and March 31, 2015 1,497 1,100 2,559 2,096 ____________________________________________ (a) In the Current Quarter, holders of our 5.75% Cumulative Convertible Preferred Stock converted 24,601 shares into 975,488 shares of common stock. Also, in the Current Quarter, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 1,201 shares into 46,018 shares of common stock. Dividends In January 2016, we announced that we were suspending dividend payments 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. Our preferred stock dividends in arrears for the Current Quarter are detailed below. 5.75% 5.75% (A) 4.50% 5.00% ($ in millions) Dividends in arrears $ 21 $ 16 $ 3 $ 3 Accumulated Other Comprehensive Income (Loss) For the Current Quarter and the Prior Quarter, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Net Change ($ in millions) Balance, December 31, 2015 $ (99 ) $ (99 ) Other comprehensive income before reclassifications (4 ) (4 ) Amounts reclassified from accumulated other comprehensive income 4 4 Net other comprehensive income — — Balance, March 31, 2016 $ (99 ) $ (99 ) Balance, December 31, 2014 $ (143 ) $ (143 ) Other comprehensive income before reclassifications (1 ) (1 ) Amounts reclassified from accumulated other comprehensive income 10 10 Net other comprehensive income 9 9 Balance, March 31, 2015 $ (134 ) $ (134 ) For the Current Quarter and the Prior Quarter, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed 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) Three Months Ended March 31, 2016 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 4 Total reclassifications for the period, net of tax $ 4 Three Months Ended March 31, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 10 Total reclassifications for the period, net of tax $ 10

Share-Based Compensation (Note)

Share-Based Compensation (Note)	3 Months Ended
	Mar. 31, 2016
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. 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. A summary of the changes in unvested restricted stock during the Current Quarter is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2016 10,455 $ 17.31 Granted 2,728 $ 3.76 Vested (3,392 ) $ 17.55 Forfeited (141 ) $ 16.48 Unvested restricted stock as of March 31, 2016 9,650 $ 13.41 The aggregate intrinsic value of restricted stock that vested during the Current Quarter was approximately $14 million based on the stock price at the time of vesting. As of March 31, 2016 , there was approximately $99 million of total unrecognized compensation expense related to unvested restricted stock. The expense is expected to be recognized over a weighted average period of approximately 1.76 years. Stock Options. In the Current Quarter and the Prior Quarter, we granted members of senior management stock options that vest ratably over a three -year period. In January 2013, we also granted retention awards of stock options to certain officers that vest one-third on each of the third , fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options expire seven to ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter: Expected option life – years 6.0 Volatility 46.07 % Risk-free interest rate 1.70 % Dividend yield — % The following table provides information related to stock option activity in the Current Quarter: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding as of January 1, 2016 5,377 $ 19.37 5.80 $ — Granted 4,932 $ 3.71 Exercised — $ — $ — Expired (176 ) $ 18.42 Forfeited (945 ) $ 5.66 Outstanding as of March 31, 2016 9,188 $ 12.39 7.47 $ 2 Exercisable as of March 31, 2016 3,208 $ 19.57 4.93 $ — ___________________________________________ (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 March 31, 2016 , there was $14 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.13 years . Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 8 $ 12 Oil and natural gas properties 4 7 Oil, natural gas and NGL production expenses 3 4 Marketing, gathering and compression expenses 1 1 Total $ 16 $ 24 Liability-Classified Awards Performance Share Units. 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 levels. For PSUs granted in 2016, the TSR component can range from 0% to 100% and the operational component can range from 0% to 100% , resulting in a maximum payout of 200% . The payout percentage of these PSUs is capped at 100% if the Company's absolute TSR is less than zero. 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. 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 69.41 % Risk-free interest rate 0.84 % Dividend yield for value of awards — % The following table presents a summary of our 2016, 2015 and 2014 PSU awards: Grant Date Fair Value March 31, 2016 Units Fair Value Vested Liability ($ in millions) 2016 Awards: Payable 2019 2,348,893 $ 10 $ 11 $ 2 2015 Awards: Payable 2018 629,694 $ 13 $ 2 $ 1 2014 Awards: Payable 2017 561,215 $ 16 $ 1 $ 1 PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 2 $ (10 ) Restructuring and other termination costs 1 (10 ) Oil and natural gas properties — (1 ) Total $ 3 $ (21 )

Derivative and Hedging Activiti

Derivative and Hedging Activities (Note)	3 Months Ended
	Mar. 31, 2016
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 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 March 31, 2016 and December 31, 2015, 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 March 31, 2016 and December 31, 2015 are provided below. March 31, 2016 December 31, 2015 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 21.2 $ 78 13.5 $ 144 Call options 15.7 (4 ) 19.2 (7 ) Total oil 36.9 74 32.7 137 Natural gas (tbtu): Fixed-price swaps 438 241 500 229 Call options 250 (65 ) 295 (99 ) Basis protection swaps 40 (9 ) 57 — Total natural gas 728 167 852 130 Total estimated fair value $ 241 $ 267 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 March 31, 2016 and December 31, 2015, there were no interest rate derivatives outstanding. 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 6.25% Euro-denominated Senior Notes due 2017, 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 in 2015 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 condensed consolidated balance sheets as liabilities of $43 million and $52 million as of March 31, 2016 and December 31, 2015, respectively. The euro-denominated debt in long-term debt has been adjusted to $344 million as of March 31, 2016 , using an exchange rate of $1.1380 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. The bifurcated derivative is measured at fair value on a quarterly basis resulting in an unrealized gain of $20 million in the Current Quarter. Both settlements and mark-to-market gains (losses) are included in marketing, gathering and compression revenues in our condensed consolidated statements of operations. Effect of Derivative Instruments – Condensed Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet ($ in millions) As of March 31, 2016 Commodity Contracts: Short-term derivative asset $ 345 $ (49 ) $ 296 Short-term derivative liability (92 ) 49 (43 ) Long-term derivative liability (12 ) — (12 ) Total commodity contracts 241 — 241 Foreign Currency Contracts: (a) Short-term derivative liability (43 ) — (43 ) Total foreign currency contracts (43 ) — (43 ) Supply Contracts: Short-term derivative asset 54 — 54 Long-term derivative asset 263 — 263 Total supply contracts 317 — 317 Total derivatives $ 515 $ — $ 515 As of December 31, 2015 Commodity Contracts: Short-term derivative asset $ 381 $ (66 ) $ 315 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 ____________________________________________ (a) Designated as cash flow hedging instruments. As of March 31, 2016 and December 31, 2015, we did not have any cash collateral balances for these derivatives. Effect of Derivative Instruments – Condensed Consolidated Statements of Operations The components of oil, natural gas and NGL revenues for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Oil, natural gas and NGL revenues $ 812 $ 1,382 Gains (losses) on undesignated oil and natural gas derivatives 192 178 Losses on terminated cash flow hedges (11 ) (17 ) Total oil, natural gas and NGL revenues $ 993 $ 1,543 The components of marketing, gathering and compression revenues for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Marketing, gathering and compression revenues $ 940 $ 1,675 Gains on undesignated supply contract derivatives 20 — Total marketing, gathering and compression revenues $ 960 $ 1,675 The components of interest expense for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Interest expense on senior notes $ 115 $ 171 Amortization of loan discount, issuance costs and other 10 11 Interest expense on credit facilities 5 3 Gains on terminated fair value hedges — (1 ) (Gains) losses on undesignated interest rate derivatives — (10 ) Capitalized interest (68 ) (123 ) Total interest expense $ 62 $ 51 Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below. Three Months Ended March 31, 2016 2015 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (160 ) $ (99 ) $ (231 ) $ (143 ) Net change in fair value (7 ) (4 ) (2 ) (1 ) Losses reclassified to income 11 4 17 10 Balance, end of period $ (156 ) $ (99 ) $ (216 ) $ (134 ) Approximately $109 million of the $99 million of accumulated other comprehensive loss as of March 31, 2016 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 March 31, 2016 , 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 March 31, 2016 , our oil, natural gas, foreign currency and supply contract derivative instruments were spread among 13 counterparties. Hedging Arrangements In 2015, we began entering into bilateral hedging agreements. 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 March 31, 2016 , we had hedged under bilateral agreements 152.5 mmboe of our future production with price derivatives and 6.5 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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Derivative Assets (Liabilities): Commodity assets $ — $ 325 $ 20 $ 345 Commodity liabilities — (36 ) (68 ) (104 ) Foreign currency liabilities — (43 ) — (43 ) Supply contract assets — — 317 317 Total derivatives $ — $ 246 $ 269 $ 515 As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of December 31, 2015 $ (91 ) $ 297 Total gains (losses) (unrealized): Included in earnings (a) 25 33 Total purchases, issuances, sales and settlements: Settlements 18 (13 ) Ending balance as of March 31, 2016 $ (48 ) $ 317 Beginning balance as of December 31, 2014 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 78 — Total purchases, issuances, sales and settlements: Settlements (93 ) — Transfers (b) — — Ending balance as of March 31, 2015 $ (69 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2016 2015 2016 2015 ($ in millions) Total gains (losses) included in earnings for the period $ 25 $ 78 $ 20 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 21 $ 74 $ 20 $ — (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 March 31, 2016 : Instrument Type Unobservable Input Range Weighted Average Fair Value March 31, 2016 ($ in millions) Oil trades (a) Oil price volatility curves 26.58% – 37.92% 33.98% $ (4 ) Supply contracts (b) Oil price volatility curves 20.72% – 43.45% 25.61% $ 317 Natural gas trades (a) Natural gas price volatility curves 19.69% – 47.43% 32.54% $ (44 ) ___________________________________________ (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)	3 Months Ended
	Mar. 31, 2016
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. During the Current Quarter, we received proceeds of $140 million for the sale of oil and natural gas properties, partially offset by $78 million in post-close adjustments and other settlements for prior period divestitures. During the Prior Quarter, we received net proceeds of $21 million related to divestitures of noncore oil and natural gas properties. 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 condensed 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 March 31, 2016 , 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 the Current Quarter and the Prior Quarter were as follows: Three Months Ended March 31, 2016 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 66.0 1.8 222.7 3.5 9 39.4 3.4 89.3 4.1 4 10.1 1.9 — 2.0 3 — 1.5 — 1.5 2 — 0.9 — 0.9 1 — 3.3 — 3.3 115.5 12.8 312.0 15.3 Three Months Ended March 31, 2015 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 83.0 2.2 276.3 4.4 9 43.6 3.7 97.0 4.5 8 (a) — 14.0 — 14.0 4 11.0 2.1 — 2.1 3 — 1.7 — 1.7 2 — 1.1 — 1.1 1 — 3.5 — 3.5 137.6 28.3 373.3 31.3 ____________________________________________ (a) VPP #8 expired in August 2015. The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2016 were as follows: Volume Remaining as of March 31, 2016 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 71 0.9 27.7 3.4 53.9 9 59 0.6 55.7 1.5 68.3 4 9 — 5.4 — 5.6 3 40 — 16.0 — 16.0 2 37 — 8.9 — 8.9 1 81 — 75.0 — 75.0 1.5 188.7 4.9 227.7

Variable Interest Entities (Not

Variable Interest Entities (Note)	3 Months Ended
	Mar. 31, 2016
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 . 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 and because the royalty interest owners, other than Chesapeake, do not have the ability to exercise substantial liquidation rights. 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. As of March 31, 2016 and December 31, 2015, we had $260 million and $259 million , respectively, of noncontrolling interests on our condensed consolidated balance sheets attributable to the Trust. In the Current Quarter, we had a net loss of a nominal amount and in the Prior Quarter we had net income of $1 million attributable to the Trust’s noncontrolling interests recorded in our condensed consolidated statements of operations. 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 March 31, 2016 , $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $445 million of accumulated depreciation, depletion and amortization and $2 million of other current liabilities were attributable to the Trust. We have presented parenthetically on the face of the condensed 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 was to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. The partnership was an unconsolidated VIE, and the carrying value of our equity investment was $10 million as of December 31, 2015. In the Current Quarter, we sold certain mineral interests held outside the partnership for approximately $9 million , and assigned our interest in the partnership to KKR, which eliminated our future commitments to acquire additional mineral interests. As a result of the transaction, we wrote off our equity investment and recognized a $10 million loss.

Impairments (Note)

Impairments (Note)	3 Months Ended
	Mar. 31, 2016
Asset Impairment Charges [Abstract]
Asset Impairment Charges Disclosure	Impairments Impairments of Oil and Natural Gas Properties 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. In the Current Quarter and the Prior Quarter, 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 $853 million and $4.976 billion , respectively. Cash flow hedges which relate to future periods increased the ceiling test impairment by $166 million and $195 million in the Current Quarter and the Prior Quarter, respectively. Based on the first-day-of-the-month prices we have received over the 11 months ended May 1, 2016 , as well as the current strip price for June 2016, we expect to record another material write-down in the carrying value of our oil and natural gas properties in the second quarter of 2016 . Further material write-downs in subsequent quarters will occur if the trailing 12-month commodity prices continue to fall as compared to the commodity prices used in prior quarters. Impairments of Fixed Assets and Other We review our long-lived assets, other than oil and natural gas properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable. We recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter and the Prior Quarter is as follows: Three Months Ended 2016 2015 ($ in millions) Natural gas compressors $ 20 $ — Buildings and land 7 — Other 11 4 Total impairments of fixed assets and other $ 38 $ 4 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.

Income Taxes (Note)

Income Taxes (Note)	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax Disclosure	Income Taxes 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 the taxable income is generated, to determine whether a valuation allowance is required. The 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. Based on our estimated operating results for the subsequent quarters, we project being in a net deferred tax asset position as of December 31, 2016. 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 projected cumulative loss incurred over the three-year period ending December 31, 2016. The 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 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.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements (Note)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Financial Assets (Liabilities): Other current assets $ 48 $ — $ — $ 48 Other current liabilities (50 ) — — (50 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 ) See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives. Nonrecurring Fair Value Measurements See Note 11 regarding nonrecurring fair value measurements.

Segment Information (Note)

Segment Information (Note)	3 Months Ended
	Mar. 31, 2016
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Segment Information Disclosure	Segment Information As of March 31, 2016 , 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. 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 $783 million and $1.233 billion for the Current Quarter and the Prior Quarter, respectively. During the Current Quarter, we changed the structure of our internal organization to include certain assets in our Exploration and Production reportable segment instead of our Other segment. Accordingly, this change has been reflected through retroactive revision of the segment information as of December 31, 2015. The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Other Intercompany Eliminations Consolidated Total ($ in millions) Three Months Ended March 31, 2016 Revenues $ 993 $ 1,743 $ — $ (783 ) $ 1,953 Intersegment revenues — (783 ) — 783 — Total revenues $ 993 $ 960 $ — $ — $ 1,953 Income (Loss) Before Income Taxes $ (895 ) $ 40 $ (9 ) $ (57 ) $ (921 ) Three Months Ended March 31, 2015 Revenues $ 1,520 $ 2,908 $ — $ (1,210 ) $ 3,218 Intersegment revenues 23 (1,233 ) — 1,210 — Total revenues $ 1,543 $ 1,675 $ — $ — $ 3,218 Income (Loss) Before Income Taxes $ (5,349 ) $ 4 $ (14 ) $ 267 $ (5,092 ) As of March 31, 2016 Total Assets $ 12,624 $ 1,425 $ 1,468 $ (160 ) $ 15,357 As of December 31, 2015 Total Assets (as previously reported) $ 11,776 $ 1,524 $ 4,325 $ (311 ) $ 17,314 As of Total Assets (as revised) $ 14,610 $ 1,524 $ 1,491 $ (311 ) $ 17,314

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Note)	3 Months Ended
	Mar. 31, 2016
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 and has no independent assets or operations. 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. Our non-guarantor subsidiaries are minor and, as such, we have not included condensed consolidating financial information.

Recently Issued Accounting Stan

Recently Issued Accounting Standards (Note)	3 Months Ended
	Mar. 31, 2016
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 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. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In March 2016, the FASB issued guidance for improvements to employee share-based payment accounting to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the income statement and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity included with income tax cash flows. For public business entities, the amendments are effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. We have elected to early adopt the amendments in the Current Quarter. The cumulative-effect adjustment to retained earnings for all excess tax benefits not previously recognized as of the beginning period is fully offset by a corresponding change in the valuation allowance resulting in no change. The implementation of this guidance did not have a material impact on our consolidated financial statements and related disclosures. In March 2016, the FASB issued new guidance that will result in fewer put or call options embedded in debt instruments qualifying for separate derivative accounting because companies will not be required to assess whether the contingent event, such as change in control or an IPO, is related to interest rates or credit risks. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In August 2014, the FASB issued updated guidance that requires management, for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued. If management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, certain disclosures are required to be made within the footnotes to the consolidated financial statements. The amendments in this update are effective for annual periods ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.

Subsequent Events (Subsequent E

Subsequent Events (Subsequent Events (Note)	3 Months Ended
	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events In May 2016, we executed a sales agreement to sell approximately 42,000 net acres prospective for the STACK play in Oklahoma for approximately $470 million . In April 2016, we further amended our revolving credit agreement. See Note 3 for further discussion of the terms of our credit facility.

Basis of Presentation and Sum27

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Basis of Accounting Policy	The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation ("Chesapeake" or the "Company") and its subsidiaries 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.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	3 Months Ended
	Mar. 31, 2016
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Consolidation, Variable Interest Entity, Policy	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)	3 Months Ended
	Mar. 31, 2016
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.

Income Taxes Income Taxes (Poli

Income Taxes Income Taxes (Policy)	3 Months Ended
	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Income Tax, Policy	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 the taxable income is generated, to determine whether a valuation allowance is required.

Recently Issued Accounting St31

Recently Issued Accounting Standards (Policies)	3 Months Ended
	Mar. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements, Policy	Recently Issued Accounting Standards In May 2014, the 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. In March 2016, the FASB issued an update clarifying the implementation guidance on principal versus agent considerations. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In February 2016, the FASB issued updated lease accounting guidance requiring companies to recognize the assets and liabilities for the rights and obligations created by long-term leases of assets on the balance sheet. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In March 2016, the FASB issued guidance for improvements to employee share-based payment accounting to simplify the accounting for share-based compensation. The new standard requires all excess tax benefits and reductions from differences between the deduction for tax purposes and the compensation cost recorded for financial reporting purposes be recognized as income tax expense or benefit in the income statement and not recognized as additional paid-in capital. The new standard also requires all excess tax benefits and deficiencies to be classified as operating activity included with income tax cash flows. For public business entities, the amendments are effective for annual periods, including interim periods within those annual periods, beginning after December 15, 2016. Early adoption is permitted in any interim or annual period, with any adjustments reflected as of the beginning of the fiscal year of adoption. We have elected to early adopt the amendments in the Current Quarter. The cumulative-effect adjustment to retained earnings for all excess tax benefits not previously recognized as of the beginning period is fully offset by a corresponding change in the valuation allowance resulting in no change. The implementation of this guidance did not have a material impact on our consolidated financial statements and related disclosures. In March 2016, the FASB issued new guidance that will result in fewer put or call options embedded in debt instruments qualifying for separate derivative accounting because companies will not be required to assess whether the contingent event, such as change in control or an IPO, is related to interest rates or credit risks. This standard is effective for fiscal years beginning after December 15, 2016, including interim periods within those years. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures. In August 2014, the FASB issued updated guidance that requires management, for each annual and interim reporting period, to evaluate whether there are conditions or events, considered in the aggregate, that raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the consolidated financial statements are issued. If management concludes that conditions or events raise substantial doubt about the entity’s ability to continue as a going concern, certain disclosures are required to be made within the footnotes to the consolidated financial statements. The amendments in this update are effective for annual periods ending after December 15, 2016 and interim periods thereafter, with early adoption permitted. We are evaluating the impact of this guidance on our consolidated financial statements and related disclosures.

Basis of Presentation and Sum32

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	3 Months Ended
	Mar. 31, 2016
Accounting Policies [Abstract]
Schedule of Debt Issusance Costs Prior Period Adjustments	The retrospective adjustment to the December 31, 2015 consolidated balance sheet is shown below. As Previously Reported December 31, 2015 Adjustment Effect As Adjusted $ in millions Other long-term assets $ 333 $ (43 ) $ 290 Long-term debt, net $ 10,354 $ 43 $ 10,311

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2016
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Antidilutive Securities Excluded From Computation Of Earnings Per Share	For the Current Quarter and the Prior Quarter, 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) Three Months Ended March 31, 2016 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 21 58 5.75% cumulative convertible preferred stock (series A) $ 16 42 5.00% cumulative convertible preferred stock (series 2005B) $ 3 6 4.50% cumulative convertible preferred stock $ 3 6 Participating securities $ — 1 Three Months Ended March 31, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 21 59 5.75% cumulative convertible preferred stock (series A) $ 16 42 5.00% cumulative convertible preferred stock (series 2005B) $ 3 6 4.50% cumulative convertible preferred stock $ 3 6 Participating securities $ — 2

Debt (Tables)

Debt (Tables)	3 Months Ended
	Mar. 31, 2016
Debt Disclosure [Abstract]
Schedule of Debt	Our long-term debt consisted of the following as of March 31, 2016 and December 31, 2015: March 31, 2016 December 31, 2015 Principal Amount Carrying Principal Carrying ($ in millions) 3.25% senior notes due 2016 $ — $ — $ 381 381 6.25% euro-denominated senior notes due 2017 (a) 344 344 329 329 6.5% senior notes due 2017 379 379 453 453 7.25% senior notes due 2018 538 538 538 538 Floating rate senior notes due 2019 1,104 1,104 1,104 1,104 6.625% senior notes due 2020 822 822 822 822 6.875% senior notes due 2020 304 304 304 304 6.125% senior notes due 2021 589 589 589 589 5.375% senior notes due 2021 286 286 286 286 4.875% senior notes due 2022 639 639 639 639 8.00% senior secured second lien notes due 2022 2,425 3,542 2,425 3,584 5.75% senior notes due 2023 384 384 384 384 2.75% contingent convertible senior notes due 2035 (b) 2 2 2 2 2.5% contingent convertible senior notes due 2037 (b)(c) 902 846 1,110 1,027 2.25% contingent convertible senior notes due 2038 (b)(c) 340 293 340 290 Revolving credit facility 367 367 — — Debt issuance costs — (38 ) — (43 ) Discount on senior notes — (3 ) — (4 ) Interest rate derivatives (d) — 7 — 7 Total debt, net 9,425 10,405 9,706 10,692 Less current maturities of long-term debt, net (e) (344 ) (343 ) (381 ) (381 ) Total long-term debt, net $ 9,081 $ 10,062 $ 9,325 $ 10,311 ___________________________________________ (a) The principal and carrying amounts shown are based on the exchange rate of $1.1380 to €1.00 and $1.0862 to €1.00 as of March 31, 2016 and December 31, 2015, respectively. See Foreign Currency Derivatives in Note 8 for information on our related foreign currency derivatives. (b) 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 Current Quarter, 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 second 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 Current Quarter and the Prior Quarter. 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. We may redeem our 2.75% Contingent Convertible Senior Notes due 2035 at any time. (c) Discount as of March 31, 2016 and December 31, 2015 included $103 million and $133 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (d) See Interest Rate Derivatives in Note 8 for further discussion related to these instruments. (e) As of March 31, 2016 , current maturities of long-term debt, net includes our 6.25% Euro-denominated Senior Notes due 2017
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. March 31, 2016 December 31, 2015 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 343 $ 250 $ 381 $ 366 Long-term debt (Level 1) $ 9,688 $ 4,029 $ 10,347 $ 3,735 Long-term debt (Level 2) $ 367 $ 250 $ — $ —

Contingencies and Commitments35

Contingencies and Commitments (Tables)	3 Months Ended
	Mar. 31, 2016
Commitments and Contingencies Disclosure [Abstract]
Gathering, Processing and Transportation Commitments	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. March 31, ($ in millions) 2016 $ 1,383 2017 1,880 2018 1,676 2019 1,378 2020 1,051 2021 – 2099 6,696 Total $ 14,064

Other Liabilities (Tables)

Other Liabilities (Tables)	3 Months Ended
	Mar. 31, 2016
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	Other current liabilities as of March 31, 2016 and December 31, 2015 are detailed below. March 31, December 31, ($ in millions) Revenues and royalties due others $ 378 $ 500 Accrued drilling and production costs 216 212 Joint interest prepayments received 103 169 Accrued compensation and benefits 151 264 Other accrued taxes 57 37 Bank of New York Mellon legal accrual 439 439 Minimum gathering volume commitment 4 201 Other 196 397 Total other current liabilities $ 1,544 $ 2,219
Other Long-Term Liabilities	Other long-term liabilities as of March 31, 2016 and December 31, 2015 are detailed below. March 31, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 183 $ 190 Financing obligations 29 29 Unrecognized tax benefits 68 64 Other 146 126 Total other long-term liabilities $ 426 $ 409 ____________________________________________ (a) The CHK Utica, L.L.C. investors’ right to receive, proportionately, a 3% overriding royalty interest (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. The liability represents the obligation to deliver future ORRIs. Approximately $25 million and $21 million of the total $208 million and $211 million obligations are recorded in other current liabilities as of March 31, 2016 and December 31, 2015, respectively.

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2016
Equity [Abstract]
Schedule of Common Stock Outstanding Roll Forward	The following is a summary of the changes in our common shares issued for the Current Quarter and the Prior Quarter: Three Months Ended 2016 2015 (in thousands) Shares issued as of January 1 664,796 664,944 Exchange of convertible notes 14,699 — Exchange of senior notes 2,556 — Conversion of preferred stock 1,022 — Restricted stock issuances (net of forfeitures and cancellations) 1,488 151 Stock option exercises — 14 Shares issued as of March 31 684,561 665,109
Schedule of Stock by Class,Preferred Stock Conversion Terms	Outstanding shares of our preferred stock for the Current Quarter and the Prior Quarter are detailed below. 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2016 1,497 1,100 2,559 2,096 Preferred stock conversions (a) (25 ) (1 ) — — Shares outstanding as of March 31, 2016 1,472 1,099 2,559 2,096 Shares outstanding as of January 1, 2015 and March 31, 2015 1,497 1,100 2,559 2,096 ____________________________________________ (a) In the Current Quarter, holders of our 5.75% Cumulative Convertible Preferred Stock converted 24,601 shares into 975,488 shares of common stock. Also, in the Current Quarter, holders of our 5.75% (Series A) Cumulative Convertible Preferred Stock converted 1,201 shares into 46,018 shares of common stock.
Schedule of Dividends Payable	Our preferred stock dividends in arrears for the Current Quarter are detailed below. 5.75% 5.75% (A) 4.50% 5.00% ($ in millions) Dividends in arrears $ 21 $ 16 $ 3 $ 3
Schedule of Accumulated Other Comprehensive Income (Loss)	For the Current Quarter and the Prior Quarter, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Net Change ($ in millions) Balance, December 31, 2015 $ (99 ) $ (99 ) Other comprehensive income before reclassifications (4 ) (4 ) Amounts reclassified from accumulated other comprehensive income 4 4 Net other comprehensive income — — Balance, March 31, 2016 $ (99 ) $ (99 ) Balance, December 31, 2014 $ (143 ) $ (143 ) Other comprehensive income before reclassifications (1 ) (1 ) Amounts reclassified from accumulated other comprehensive income 10 10 Net other comprehensive income 9 9 Balance, March 31, 2015 $ (134 ) $ (134 )
Reclassification out of Accumulated Other Comprehensive Income	For the Current Quarter and the Prior Quarter, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed 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) Three Months Ended March 31, 2016 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 4 Total reclassifications for the period, net of tax $ 4 Three Months Ended March 31, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 10 Total reclassifications for the period, net of tax $ 10

Share-Based Compensation (Table

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2016
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 the Current Quarter is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2016 10,455 $ 17.31 Granted 2,728 $ 3.76 Vested (3,392 ) $ 17.55 Forfeited (141 ) $ 16.48 Unvested restricted stock as of March 31, 2016 9,650 $ 13.41
Equity-Classified Share-Based Payment Award Valuation Assumptions	The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter: Expected option life – years 6.0 Volatility 46.07 % Risk-free interest rate 1.70 % Dividend yield — % 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 69.41 % Risk-free interest rate 0.84 % Dividend yield for value of awards — %
Schedule of Share-Based Compensation, Stock Options, Activity	The following table provides information related to stock option activity in the Current Quarter: 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 as of January 1, 2016 5,377 $ 19.37 5.80 $ — Granted 4,932 $ 3.71 Exercised — $ — $ — Expired (176 ) $ 18.42 Forfeited (945 ) $ 5.66 Outstanding as of March 31, 2016 9,188 $ 12.39 7.47 $ 2 Exercisable as of March 31, 2016 3,208 $ 19.57 4.93 $ — ___________________________________________ (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 (credits) related to PSUs for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 2 $ (10 ) Restructuring and other termination costs 1 (10 ) Oil and natural gas properties — (1 ) Total $ 3 $ (21 ) We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 8 $ 12 Oil and natural gas properties 4 7 Oil, natural gas and NGL production expenses 3 4 Marketing, gathering and compression expenses 1 1 Total $ 16 $ 24
Liability-Classified Share-Based Payment Award Valuation Assumptions	The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter: Expected option life – years 6.0 Volatility 46.07 % Risk-free interest rate 1.70 % Dividend yield — % 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 69.41 % Risk-free interest rate 0.84 % Dividend yield for value of awards — %
Schedule of Nonvested Performance-based Units Activity	The following table presents a summary of our 2016, 2015 and 2014 PSU awards: Grant Date Fair Value March 31, 2016 Units Fair Value Vested Liability ($ in millions) 2016 Awards: Payable 2019 2,348,893 $ 10 $ 11 $ 2 2015 Awards: Payable 2018 629,694 $ 13 $ 2 $ 1 2014 Awards: Payable 2017 561,215 $ 16 $ 1 $ 1
Liability-Classified Stock-Based Compensation	We recognized the following compensation costs (credits) related to PSUs for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 2 $ (10 ) Restructuring and other termination costs 1 (10 ) Oil and natural gas properties — (1 ) Total $ 3 $ (21 ) We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter and the Prior Quarter: Three Months Ended March 31, 2016 2015 ($ in millions) General and administrative expenses $ 8 $ 12 Oil and natural gas properties 4 7 Oil, natural gas and NGL production expenses 3 4 Marketing, gathering and compression expenses 1 1 Total $ 16 $ 24

Derivative and Hedging Activi39

Derivative and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 2016
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 March 31, 2016 and December 31, 2015 are provided below. March 31, 2016 December 31, 2015 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 21.2 $ 78 13.5 $ 144 Call options 15.7 (4 ) 19.2 (7 ) Total oil 36.9 74 32.7 137 Natural gas (tbtu): Fixed-price swaps 438 241 500 229 Call options 250 (65 ) 295 (99 ) Basis protection swaps 40 (9 ) 57 — Total natural gas 728 167 852 130 Total estimated fair value $ 241 $ 267
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 condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet ($ in millions) As of March 31, 2016 Commodity Contracts: Short-term derivative asset $ 345 $ (49 ) $ 296 Short-term derivative liability (92 ) 49 (43 ) Long-term derivative liability (12 ) — (12 ) Total commodity contracts 241 — 241 Foreign Currency Contracts: (a) Short-term derivative liability (43 ) — (43 ) Total foreign currency contracts (43 ) — (43 ) Supply Contracts: Short-term derivative asset 54 — 54 Long-term derivative asset 263 — 263 Total supply contracts 317 — 317 Total derivatives $ 515 $ — $ 515 As of December 31, 2015 Commodity Contracts: Short-term derivative asset $ 381 $ (66 ) $ 315 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 ____________________________________________ (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 Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Oil, natural gas and NGL revenues $ 812 $ 1,382 Gains (losses) on undesignated oil and natural gas derivatives 192 178 Losses on terminated cash flow hedges (11 ) (17 ) Total oil, natural gas and NGL revenues $ 993 $ 1,543 The components of marketing, gathering and compression revenues for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Marketing, gathering and compression revenues $ 940 $ 1,675 Gains on undesignated supply contract derivatives 20 — Total marketing, gathering and compression revenues $ 960 $ 1,675
Schedule of Derivative Instruments, Marketing, Gathering and Compression Sales	The components of oil, natural gas and NGL revenues for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Oil, natural gas and NGL revenues $ 812 $ 1,382 Gains (losses) on undesignated oil and natural gas derivatives 192 178 Losses on terminated cash flow hedges (11 ) (17 ) Total oil, natural gas and NGL revenues $ 993 $ 1,543 The components of marketing, gathering and compression revenues for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Marketing, gathering and compression revenues $ 940 $ 1,675 Gains on undesignated supply contract derivatives 20 — Total marketing, gathering and compression revenues $ 960 $ 1,675
Interest Income And Interest Expense Disclosure	The components of interest expense for the Current Quarter and the Prior Quarter are presented below. Three Months Ended March 31, 2016 2015 ($ in millions) Interest expense on senior notes $ 115 $ 171 Amortization of loan discount, issuance costs and other 10 11 Interest expense on credit facilities 5 3 Gains on terminated fair value hedges — (1 ) (Gains) losses on undesignated interest rate derivatives — (10 ) Capitalized interest (68 ) (123 ) Total interest expense $ 62 $ 51
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 condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below. Three Months Ended March 31, 2016 2015 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (160 ) $ (99 ) $ (231 ) $ (143 ) Net change in fair value (7 ) (4 ) (2 ) (1 ) Losses reclassified to income 11 4 17 10 Balance, end of period $ (156 ) $ (99 ) $ (216 ) $ (134 )
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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Derivative Assets (Liabilities): Commodity assets $ — $ 325 $ 20 $ 345 Commodity liabilities — (36 ) (68 ) (104 ) Foreign currency liabilities — (43 ) — (43 ) Supply contract assets — — 317 317 Total derivatives $ — $ 246 $ 269 $ 515 As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of December 31, 2015 $ (91 ) $ 297 Total gains (losses) (unrealized): Included in earnings (a) 25 33 Total purchases, issuances, sales and settlements: Settlements 18 (13 ) Ending balance as of March 31, 2016 $ (48 ) $ 317 Beginning balance as of December 31, 2014 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 78 — Total purchases, issuances, sales and settlements: Settlements (93 ) — Transfers (b) — — Ending balance as of March 31, 2015 $ (69 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2016 2015 2016 2015 ($ in millions) Total gains (losses) included in earnings for the period $ 25 $ 78 $ 20 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 21 $ 74 $ 20 $ — (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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Financial Assets (Liabilities): Other current assets $ 48 $ — $ — $ 48 Other current liabilities (50 ) — — (50 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) 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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Derivative Assets (Liabilities): Commodity assets $ — $ 325 $ 20 $ 345 Commodity liabilities — (36 ) (68 ) (104 ) Foreign currency liabilities — (43 ) — (43 ) Supply contract assets — — 317 317 Total derivatives $ — $ 246 $ 269 $ 515 As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of December 31, 2015 $ (91 ) $ 297 Total gains (losses) (unrealized): Included in earnings (a) 25 33 Total purchases, issuances, sales and settlements: Settlements 18 (13 ) Ending balance as of March 31, 2016 $ (48 ) $ 317 Beginning balance as of December 31, 2014 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 78 — Total purchases, issuances, sales and settlements: Settlements (93 ) — Transfers (b) — — Ending balance as of March 31, 2015 $ (69 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2016 2015 2016 2015 ($ in millions) Total gains (losses) included in earnings for the period $ 25 $ 78 $ 20 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 21 $ 74 $ 20 $ — (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 March 31, 2016 : Instrument Type Unobservable Input Range Weighted Average Fair Value March 31, 2016 ($ in millions) Oil trades (a) Oil price volatility curves 26.58% – 37.92% 33.98% $ (4 ) Supply contracts (b) Oil price volatility curves 20.72% – 43.45% 25.61% $ 317 Natural gas trades (a) Natural gas price volatility curves 19.69% – 47.43% 32.54% $ (44 ) ___________________________________________ (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 40

Oil and Natural Gas Property Transactions (Tables)	3 Months Ended
	Mar. 31, 2016
Property, Plant and Equipment [Abstract]
VPP Transactions	As of March 31, 2016 , 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 the Current Quarter and the Prior Quarter were as follows: Three Months Ended March 31, 2016 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 66.0 1.8 222.7 3.5 9 39.4 3.4 89.3 4.1 4 10.1 1.9 — 2.0 3 — 1.5 — 1.5 2 — 0.9 — 0.9 1 — 3.3 — 3.3 115.5 12.8 312.0 15.3 Three Months Ended March 31, 2015 VPP # Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) 10 83.0 2.2 276.3 4.4 9 43.6 3.7 97.0 4.5 8 (a) — 14.0 — 14.0 4 11.0 2.1 — 2.1 3 — 1.7 — 1.7 2 — 1.1 — 1.1 1 — 3.5 — 3.5 137.6 28.3 373.3 31.3 ____________________________________________ (a) VPP #8 expired in August 2015.
VPP Volumes Remaining to Be Delivered	The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2016 were as follows: Volume Remaining as of March 31, 2016 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 71 0.9 27.7 3.4 53.9 9 59 0.6 55.7 1.5 68.3 4 9 — 5.4 — 5.6 3 40 — 16.0 — 16.0 2 37 — 8.9 — 8.9 1 81 — 75.0 — 75.0 1.5 188.7 4.9 227.7

Impairments (Tables)

Impairments (Tables)	3 Months Ended
	Mar. 31, 2016
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 Current Quarter and the Prior Quarter is as follows: Three Months Ended 2016 2015 ($ in millions) Natural gas compressors $ 20 $ — Buildings and land 7 — Other 11 4 Total impairments of fixed assets and other $ 38 $ 4

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2016 and December 31, 2015: 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 March 31, 2016 Derivative Assets (Liabilities): Commodity assets $ — $ 325 $ 20 $ 345 Commodity liabilities — (36 ) (68 ) (104 ) Foreign currency liabilities — (43 ) — (43 ) Supply contract assets — — 317 317 Total derivatives $ — $ 246 $ 269 $ 515 As of December 31, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 372 $ 9 $ 381 Commodity liabilities — (14 ) (100 ) (114 ) Foreign currency liabilities — (52 ) — (52 ) Supply contract assets — — 297 297 Total derivatives $ — $ 306 $ 206 $ 512 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Quarter and the Prior Quarter is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of December 31, 2015 $ (91 ) $ 297 Total gains (losses) (unrealized): Included in earnings (a) 25 33 Total purchases, issuances, sales and settlements: Settlements 18 (13 ) Ending balance as of March 31, 2016 $ (48 ) $ 317 Beginning balance as of December 31, 2014 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 78 — Total purchases, issuances, sales and settlements: Settlements (93 ) — Transfers (b) — — Ending balance as of March 31, 2015 $ (69 ) $ 1 ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2016 2015 2016 2015 ($ in millions) Total gains (losses) included in earnings for the period $ 25 $ 78 $ 20 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 21 $ 74 $ 20 $ — (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 March 31, 2016 and December 31, 2015: 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 March 31, 2016 Financial Assets (Liabilities): Other current assets $ 48 $ — $ — $ 48 Other current liabilities (50 ) — — (50 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2015 Financial Assets (Liabilities): Other current assets $ 50 $ — $ — $ 50 Other current liabilities (51 ) — — (51 ) Total $ (1 ) $ — $ — $ (1 )

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2016
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 Other Intercompany Eliminations Consolidated Total ($ in millions) Three Months Ended March 31, 2016 Revenues $ 993 $ 1,743 $ — $ (783 ) $ 1,953 Intersegment revenues — (783 ) — 783 — Total revenues $ 993 $ 960 $ — $ — $ 1,953 Income (Loss) Before Income Taxes $ (895 ) $ 40 $ (9 ) $ (57 ) $ (921 ) Three Months Ended March 31, 2015 Revenues $ 1,520 $ 2,908 $ — $ (1,210 ) $ 3,218 Intersegment revenues 23 (1,233 ) — 1,210 — Total revenues $ 1,543 $ 1,675 $ — $ — $ 3,218 Income (Loss) Before Income Taxes $ (5,349 ) $ 4 $ (14 ) $ 267 $ (5,092 ) As of March 31, 2016 Total Assets $ 12,624 $ 1,425 $ 1,468 $ (160 ) $ 15,357 As of December 31, 2015 Total Assets (as previously reported) $ 11,776 $ 1,524 $ 4,325 $ (311 ) $ 17,314 As of Total Assets (as revised) $ 14,610 $ 1,524 $ 1,491 $ (311 ) $ 17,314

Basis of Presentation and Sum44

Basis of Presentation and Summary of Significant Accounting Policies Basis of Presentation and Summary of Significant Accounting Policies Debt Reclassifications Table (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other long-term assets	$ 311	$ 290
Long-term debt, net	10,062	10,311
Scenario, Previously Reported [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other long-term assets		333
Long-term debt, net		$ 10,354
Restatement Adjustment [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Other long-term assets	(43)
Long-term debt, net	$ 43

Basis of Presentation and Sum45

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	May. 02, 2016	Apr. 08, 2016	Mar. 31, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2017	Aug. 31, 2017	May. 31, 2017	Jan. 31, 2017	Dec. 31, 2014
Summary of Significant Accounting Policies [Table] [Line Items]
Impairment of oil and natural gas properties				$ 853	$ 4,976
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest				(921)	(5,092)
Cash and cash equivalents ($1 and $1 attributable to our VIE)			$ 16	16	$ 2,907		$ 825					$ 4,108
Working Capital (Deficit)			(1,341)	(1,341)			(1,205)
Debt Instrument, Face Amount			9,425	9,425			9,706
Long-term Debt, Maturities, Repayments of Principal in Year Three			878	878
Payments to Acquire Productive Assets							3,600
Long-term Debt, Gross			10,405	10,405			10,692
Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount			$ 344	$ 344			329
Debt Instrument, Interest Rate, Stated Percentage			6.25%	6.25%
Long-term Debt, Gross			$ 344	$ 344			329
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount			$ 0	$ 0			381
Debt Instrument, Interest Rate, Stated Percentage			3.25%	3.25%
Long-term Debt, Gross			$ 0	$ 0			381
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount			$ 902	$ 902			1,110
Debt Instrument, Interest Rate, Stated Percentage			2.50%	2.50%
Long-term Debt, Gross			$ 846	$ 846			1,027
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount			$ 379	$ 379			453
Debt Instrument, Interest Rate, Stated Percentage			6.50%	6.50%
Long-term Debt, Gross			$ 379	$ 379			$ 453
Senior Notes [Member] | 6.75% Senior Notes Due 2019 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.775%	6.775%
Revolving Credit Facility [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Borrowing capacity			$ 4,000	$ 4,000
Long-term Debt, Gross			$ 367	$ 367
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]
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]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Credit Rating			“Caa3
Subsequent Event [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Line of Credit Facility, Borrowing Capacity, Description		(i) the suspension or modification of certain financial covenants and (ii) the granting of liens and security interests on substantially all of our assets, including mortgages encumbering 90% of our proved oil and gas properties that constitute borrowing base properties, all hedge contracts and personal property, subject to certain agreed upon carve outs
Collateral Posted	$ 247
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] | 6.5% Senior Notes Due 2017 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount									$ 379
Subsequent Event [Member] | Revolving Credit Facility [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Percentage of Company's Assets, Including Mortgages, Used as Security Interests		90.00%
Borrowing capacity		$ 4,000
Cash Collateral for Borrowed Securities	$ 281
Scenario, Forecast [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Long-term Debt, Maturities, Repayments of Principal in Year Two								$ 1,625
Scenario, Forecast [Member] | Senior Notes [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount											$ 344
Scenario, Forecast [Member] | Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Debt Instrument, Face Amount										$ 902
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
Scenario, Forecast [Member] | Subsequent Event [Member] | Revolving Credit Facility [Member]
Summary of Significant Accounting Policies [Table] [Line Items]
Cash Collateral for Borrowed Securities	$ 696

Earnings Per Share - Antidiluti

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 0	$ 0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1	2
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 21	$ 21
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	58	59
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 16	$ 16
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	42	42
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 3	$ 3
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6
4.50% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 3	$ 3
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6

Debt - Long-Term Debt Table (De

Debt - Long-Term Debt Table (Details) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)$ / shares$ / €	Dec. 31, 2015USD ($)$ / €	Dec. 31, 2006$ / €
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 9,425	$ 9,706
Long-term debt, current maturities including discount	(344)	(381)
Long-term Debt, Fair Value	9,081	9,325
Long-term Debt, Gross	10,405	10,692
Deferred Long-term Liability Charges	(38)	(43)
Current maturities of long-term debt, net	(343)	(381)
Long-term debt, net	$ 10,062	10,311
Commitment Period	10 years
Debt Instrument, Unamortized Discount	$ (3)	(4)
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	367
Line of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	367	0
Long-term Debt, Gross	$ 367	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, Convertible, Terms of Conversion Feature	5 days
Debt Instrument, Unamortized Discount	$ (103)	(133)
Debt Instrument, Redemption Price, Percentage	100.00%
Convertible Debt [Member] | Debt Instrument, Redemption, Period One [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	5 years
Convertible Debt [Member] | Debt Instrument, Redemption, Period Two [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	10 years
Convertible Debt [Member] | Debt Instrument, Redemption, Period Three [Member]
Long-Term Debt Instrument [Line Items]
Commitment Period	15 years
Convertible Debt [Member] | Debt Instrument, Redemption, Period Four [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	7
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	0	381
Long-term Debt, Gross	$ 0	381
Debt Instrument, Interest Rate, Stated Percentage	3.25%
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 344	329
Long-term Debt, Gross	$ 344	$ 329
Debt Instrument, Interest Rate, Stated Percentage	6.25%
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 | $ / €	1.1380	1.0862	1.3325
Debt Instrument, Interest Rate, Stated Percentage	6.25%	6.25%
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 379	$ 453
Long-term Debt, Gross	$ 379	453
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	538
Long-term Debt, Gross	$ 538	538
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	1,104
Long-term Debt, Gross	1,104	1,104
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	822	822
Long-term Debt, Gross	$ 822	822
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	304
Long-term Debt, Gross	$ 304	304
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	589
Long-term Debt, Gross	$ 589	589
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	286
Long-term Debt, Gross	$ 286	286
Debt Instrument, Interest Rate, Stated Percentage	5.375%
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 639	639
Long-term Debt, Gross	$ 639	639
Debt Instrument, Interest Rate, Stated Percentage	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	2,425
Long-term Debt, Gross	$ 3,542	3,584
Debt Instrument, Interest Rate, Stated Percentage	8.00%
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 384	384
Long-term Debt, Gross	$ 384	384
Debt Instrument, Interest Rate, Stated Percentage	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	2
Long-term Debt, Gross	$ 2	2
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	$ 902	1,110
Long-term Debt, Gross	$ 846	1,027
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	340
Long-term Debt, Gross	$ 293	$ 290
Debt Instrument, Interest Rate, Stated Percentage	2.25%

Debt - Long Term Debt Table (Ph

Debt - Long Term Debt Table (Phantom) (Details)	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument Maturity Date	Mar. 15, 2016
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
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%	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%
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%
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%
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%
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 - Senior Notes and Conting

Debt - Senior Notes and Contingent Convertible Senior Notes Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Long-Term Debt Instrument [Line Items]
Cash paid to purchase debt	$ 472	$ 0
Long-term Debt, Gross	10,405		$ 10,692
Gain (Loss) on Repurchase of Debt Instrument	100
Senior Notes [Member] | 3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Cash paid to purchase debt	$ 259
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument, Repurchased Face Amount	$ 122
Debt Instrument, Repurchase Amount	115
Long-term Debt, Gross	$ 0		381
Senior Notes [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Long-term Debt, Gross	$ 846		1,027
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument, Repurchased Face Amount	$ 59
Debt Instrument, Repurchase Amount	36
Long-term Debt, Gross	379		$ 453
Senior Notes [Member] | 6.5% Senior Notes Due 2017 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount	$ 15
Senior Notes [Member] | Common Stock [Member] | 6.5% Senior Notes Due 2017 [Member]
Long-Term Debt Instrument [Line Items]
Debt Conversion, Converted Instrument, Shares Issued	2,555,979
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, Repurchased Face Amount	$ 118
Debt Instrument, Repurchase Amount	63
Convertible Debt [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Repurchase Amount	$ 90
Convertible Debt [Member] | Common Stock [Member] | 2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Debt Conversion, Converted Instrument, Shares Issued	14,699,368

Debt - Revolving Credit Facilit

Debt - Revolving Credit Facility Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016	Apr. 08, 2016	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross									$ 10,405		$ 10,692
Debt Instrument, Face Amount									9,425		$ 9,706
Interest expense on senior notes									115	$ 171
Subsequent Event [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description				(i) the suspension or modification of certain financial covenants and (ii) the granting of liens and security interests on substantially all of our assets, including mortgages encumbering 90% of our proved oil and gas properties that constitute borrowing base properties, all hedge contracts and personal property, subject to certain agreed upon carve outs
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross									367
Letters of Credit Outstanding, Amount									619
Borrowing capacity									4,000
Revolving Credit Facility [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Interest Coverage Ratio	1.25 to 1.0							1.1 to 1.0
Amended Interest Coverage Ratio		1.25 to 1.0	1.1 to 1.0		1.25 to 1.0	1.2 to 1.0	0.70 to 1.0	0.65 to 1.0
Minimum liquidity requirement when covenant ratio is above 1.1 to 1.0						$ 500
Minimum liquidity requirement when covenant ratio is below 1.1 to 1.0			$ 750
Revolving Credit Facility [Member] | Subsequent Event [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity				$ 4,000
Revolving Credit Facility [Member] | Subsequent Event [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Covenant Terms				The amendment reduces the interest coverage ratio from 1.1 to 1.0 to 0.65 to 1.0 through the first quarter of 2017, after which it will increase to 0.70 to 1.0 through the second quarter of 2017, 1.2 to 1.0 through the third quarter of 2017 and 1.25 to 1.0 thereafter. The amendment also includes a collateral value coverage test whereby if the collateral value coverage ratio, tested as of December 31, 2016, falls below 1.1 to 1.0, the $500 million minimum liquidity covenant increases to $750 million, and if the collateral value coverage ratio, tested as of March 31, 2017, falls below 1.25 to 1.0, our borrowing ability will be reduced in order to satisfy such ratio.
Revolving Credit Facility [Member] | Subsequent Event [Member] | First Lien [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity				$ 2,500
6.75% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Supersedeas Bond									$ 461

Debt - Fair Value of Other Fina

Debt - Fair Value of Other Financial Instruments (Table) (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 9,081	$ 9,325
Fair Value, Inputs, Level 1 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	343	381
Long-term Debt, Fair Value	9,688	10,347
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	250	366
Long-term Debt, Fair Value	4,029	3,735
Fair Value, Inputs, Level 2 [Member] | Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	367	0
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 250	$ 0

Contingencies - Narrative (Deta

Contingencies - Narrative (Details) $ in Millions	Jul. 17, 2015USD ($)	Mar. 31, 2016USD ($)Lawsuit	Mar. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Provision for legal contingencies		$ 22	$ 25
Loss Contingency, Number of Putative Class Action Lawsuits | Lawsuit		3
6.75% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Loss Contingencies [Line Items]
Supersedeas Bond		$ 461
Debt Instrument, Interest Rate, Stated Percentage		6.775%
6.75% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Redemption of 2019 Notes [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Awarded, Value	$ 380
Loss Contingency, Prejudgment Interest Awarded	$ 59
Provision for legal contingencies				$ 339	$ 100
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Loss Contingencies [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.875%
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Loss Contingencies [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.125%
8.00% Senior Secured Second Lien Notes Due 2022 [Member] | Senior Notes [Member]
Loss Contingencies [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		8.00%

Commitments - Undiscounted Gath

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) - Gathering and Processing Equipment [Member] $ in Millions	Mar. 31, 2016USD ($)
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Remainder of Year	$ 1,383
Gathering, Processing and Transportation Commitment, Due in Second Year	1,880
Gathering, Processing and Transportation Commitment, Due in Third Year	1,676
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,378
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,051
Gathering, Processing and Transportation Commitment, Due after Fifth Year	6,696
Gathering, Processing and Transportation Commitment	$ 14,064

Commitments - Narrative (Detail

Commitments - Narrative (Details) $ in Millions	1 Months Ended	3 Months Ended
	Nov. 30, 2011USD ($)	Mar. 31, 2016USD ($)awellCrew
Long-term Purchase Commitment [Line Items]
Gathering Fee Escalation Rate		15.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Long-term Purchase Commitment [Line Items]
Productive Oil Wells, Number of Wells, Gross | well		69
Development Wells Drilled, Net Productive | well		106
Number Of Gross Acres | a		45,400
Number Of Net Acres | a		29,000
Maximum Amount Recoverable By Trust Under Lien | $	$ 263	$ 27
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Wells, Initial Number of Wells [Member]
Long-term Purchase Commitment [Line Items]
Development Wells Drilled, Net Productive | well		118
Minimum [Member] | Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Long-term Purchase Commitment [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust		50.00%
Maximum [Member] | Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Long-term Purchase Commitment [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust		90.00%
Drilling Rig Leases [Member]
Long-term Purchase Commitment [Line Items]
Contractual Obligation | $		$ 218
Drilling Rig Leases [Member] | Minimum [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
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Percent of Total		50.00%
Operating Leases, Future Minimum Payments Due | $		$ 161
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Agreement Through June 30, 2016 [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew		5
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Agreement Through June 30, 2017 [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew		3

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Other Current Liabilities [Line Items]
Revenues and royalties due others	$ 378	$ 500
Accrued drilling and production costs	216	212
Joint interest prepayments received	103	169
Accrued compensation and benefits	151	264
Other accrued taxes	57	37
Minimum gathering volume commitment	4	201
Other current liabilities	196	397
Total other current liabilities	1,544	2,219
Bank of New York Melton legal accrual [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	$ 439	$ 439

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)well	Dec. 31, 2015USD ($)
Other Long-Term Liabilities [Line Items]
Financing obligations	$ 29	$ 29
Other long-term liabilities	146	126
Total other long-term liabilities	426	409
Total other current liabilities	1,544	2,219
Other Noncurrent Liabilities [Member]
Other Long-Term Liabilities [Line Items]
Unrecognized Tax Benefits	68	64
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	183	190
Total other long-term liabilities	208	211
Total other current liabilities	$ 25	$ 21
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ORRI [Member]
Other Long-Term Liabilities [Line Items]
Overriding Royalty Interest Percentage	3.00%
Number of Wells, Net | well	1,500
Percentage Of Increase In Leasehold In Which Commitment To Drill Is Not Met	4.00%

Equity Equity - Common Stock Ta

Equity Equity - Common Stock Table (Details) - shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Issued Beginning of Period	664,795,509	664,944,000
Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures	1,488,000	151,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period	0	14,000
Common Stock, Shares, Issued End of Period	684,560,678	665,109,000
Convertible Note Exchange [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, Conversion of Convertible Securities	14,699,000	0
Preferred Stock Exchange [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, Conversion of Convertible Securities	1,022,000	0
Senior Note Exhange [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock Issued During Period, Shares, Conversion of Convertible Securities	2,556,000	0

Equity - Convertible Preferred

Equity - Convertible Preferred Stock Table (Details) - shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
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	7,225,713
Preferred stock, shares outstanding, beginning and end of period	7,251,515
Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Conversion of Stock, Shares Converted	25,802	0
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%
Stock Issued During Period, Shares, Conversion of Convertible Securities	975,488
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
Preferred stock, shares outstanding, end of period	1,472,000	1,497,000
Preferred stock, shares outstanding, beginning and end of period	1,497,000	1,497,000
5.75% Cumulative Convertible Preferred Stock [Member] | Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Conversion of Stock, Shares Converted	25,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%
Stock Issued During Period, Shares, Conversion of Convertible Securities	46,018
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
Preferred stock, shares outstanding, end of period	1,099,000	1,100,000
Preferred stock, shares outstanding, beginning and end of period	1,100,000	1,100,000
5.75% Cumulative Convertible Preferred Stock Series A [Member] | Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Conversion of Stock, Shares Converted	1,000
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
Preferred stock, shares outstanding, end of period	2,559,000	2,559,000
Preferred stock, shares outstanding, beginning and end of period	2,559,000	2,559,000
4.50% Cumulative Convertible Preferred Stock [Member] | Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Conversion of Stock, Shares Converted	0
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
Preferred stock, shares outstanding, end of period	2,096,000	2,096,000
Preferred stock, shares outstanding, beginning and end of period	2,096,000	2,096,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member] | Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Conversion of Stock, Shares Converted	0

Equity Equity - Dividends (Deta

Equity Equity - Dividends (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
5.75% Cumulative Convertible Preferred Stock [Member]
Dividends Payable [Line Items]
Preferred Stock, Amount of Preferred Dividends in Arrears	$ 21
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Dividends Payable [Line Items]
Preferred Stock, Amount of Preferred Dividends in Arrears	16
4.50% Cumulative Convertible Preferred Stock [Member]
Dividends Payable [Line Items]
Preferred Stock, Amount of Preferred Dividends in Arrears	3
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Dividends Payable [Line Items]
Preferred Stock, Amount of Preferred Dividends in Arrears	$ 3

Equity - AOCI Changes Net of Ta

Equity - AOCI Changes Net of Tax Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	$ (99)
Net Other Comprehensive Income	0	$ 9
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)
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	(99)	(143)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(4)	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	4	10
Net Other Comprehensive Income	0	9
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)	(134)
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	(99)	(143)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(4)	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	4	10
Net Other Comprehensive Income	0	9
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (99)	$ (134)

Equity - AOCI Reclassifications

Equity - AOCI Reclassifications Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL reserves, reclassifications from AOCI	$ 993	$ 1,543
Total reclassification from AOCI	(921)	(3,720)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total reclassification from AOCI	4	10
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	$ 4	$ 10

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock Table (Details) - Restricted Stock [Member] shares in Thousands	3 Months Ended
	Mar. 31, 2016$ / sharesshares
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 | shares	10,455
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period | shares	2,728
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period | shares	(3,392)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period | shares	(141)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End | shares	9,650
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 | $ / shares	$ 17.31
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	3.76
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares	17.55
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ / shares	16.48
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End | $ / shares	$ 13.41

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation Table (Details) - Employee Stock Option [Member]	3 Months Ended
	Mar. 31, 2016
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	6 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	46.07%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.70%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	0.00%

Share-Based Compensation - Stoc

Share-Based Compensation - Stock Option Activity Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Mar. 31, 2016	Jan. 01, 2016	Mar. 31, 2016	Mar. 31, 2015
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		5,377	5,377
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross			4,932
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period			0	(14)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period			(176)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares			(945)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End	9,188		9,188
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	3,208		3,208
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		$ 19.37	$ 19.37
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price			3.71
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price			0
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price			18.42
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price			5.66
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End	$ 12.39		12.39
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 19.57		$ 19.57
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	7 years 5 months 21 days	5 years 9 months 18 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4 years 11 months 5 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start		$ 0	$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End	$ 2		2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0		$ 0

Share-Based Compensation - Eq65

Share-Based Compensation - Equity-Classified Compensation Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 16	$ 24
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	8	12
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	4	7
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	3	4
Marketing, Gathering and Compression Expenses [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 1	$ 1

Share-Based Compensation - Liab

Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Shares [Member]	3 Months Ended
	Mar. 31, 2016
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	69.41%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.84%
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	Mar. 31, 2016	Jan. 01, 2016	Jan. 01, 2015	Jan. 01, 2014
Payable 2019 [Member] | Year of 2016 [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	2,348,893
Fair Value of Share Based Award	$ 11	$ 10
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 2
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	629,694
Fair Value of Share Based Award	$ 2		$ 13
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 1
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	561,215
Fair Value of Share Based Award	$ 1			$ 16
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 1

Share-Based Compensation - Li68

Share-Based Compensation - Liability-Classified Compensation Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 16	$ 24
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	8	12
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	4	7
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	3	(21)
Performance Shares [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	2	(10)
Performance Shares [Member] | Restructuring Charges [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	1	(10)
Performance Shares [Member] | Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ (1)

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
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	$ 14
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 99
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	1 year 9 months 4 days
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	2 years 1 month 18 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	$ 14
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
Year of 2015 [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%
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 2015 and 2016 [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 2016 [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%
Management [Member] | Year of 2016 [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 2016 [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 2016 [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 2016 [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 2016 [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	100.00%
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] | 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] | 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%
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 2014 [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 2014 [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	0.00%

Derivative and Hedging Activi70

Derivative and Hedging Activities - Derivative Instruments Table (Details) MMBbls in Millions, $ in Millions, MMBTU in Trillions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)MMBTUMMBbls	Dec. 31, 2015USD ($)MMBTUMMBbls	Mar. 31, 2015USD ($)
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 515	$ 512	$ 512
Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	36.9	32.7
Derivative Assets (Liabilities), at Fair Value, Net	$ 74	$ 137
Oil [Member] | Fixed-Price Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	21.2	13.5
Derivative Assets (Liabilities), at Fair Value, Net	$ 78	$ 144
Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	15.7	19.2
Derivative Assets (Liabilities), at Fair Value, Net	$ (4)	$ (7)
Natural Gas [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 167	$ 130
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	728	852
Natural Gas [Member] | Fixed-Price Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 241	$ 229
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	438	500
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (65)	$ (99)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	250	295
Natural Gas [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (9)	$ 0
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	40	57

Derivative and Hedging Activi71

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 515	$ 512
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	515	512	$ 512
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	241	267
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	241	267
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	241	267
Not Designated as Hedging Instrument [Member] | Supply Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	317	297
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	317	297
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	345	381
Derivative Asset, Fair Value, Gross Liability	(49)	(66)
Derivative, Fair Value, Net	296	315
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Supply Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	54	51
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	54	51
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Supply Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	263	246
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative, Fair Value, Net	263	246
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(92)	(106)
Derivative Liability, Fair Value, Gross Asset	49	66
Derivative, Fair Value, Net	(43)	(40)
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(12)	(8)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	(12)	(8)
Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(43)	(52)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	(43)	(52)
Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(43)
Derivative Liability, Fair Value, Gross Asset	0
Derivative, Fair Value, Net	$ (43)
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)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		$ (52)

Derivative and Hedging Activi72

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	$ 0	$ 10
Total oil, natural gas and NGL revenues	993	1,543
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL revenues excluding derivatives	812	1,382
Gains (losses) on undesignated oil and natural gas derivatives	192	178
Losses on terminated cash flow hedges	$ (11)	$ (17)

Derivative and Hedging Activi73

Derivative and Hedging Activities Derivative and Hedging Activities, Marketing, Gathering and Compression Sales (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Marketing, gathering and compression	$ 960	$ 1,675
Fair Value, Inputs, Level 3 [Member] | Supply Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	33	0
Marketing, Gathering And Compression [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Marketing, gathering and compression revenues excluding derivatives	940	1,675
Marketing, Gathering And Compression [Member] | Fair Value, Inputs, Level 3 [Member] | Supply Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	$ 20	$ 0

Derivative and Hedging Activi74

Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$ 115	$ 171
Amortization of loan discount, issuance costs and other	10	11
Interest expense on credit facilities	5	3
Gains on terminated fair value hedges	0	(1)
(Gains) losses on undesignated interest rate derivatives	0	(10)
Capitalized interest	(68)	(123)
Total interest expense	$ 62	$ 51

Derivative and Hedging Activi75

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	$ (99)
Other Comprehensive Income (Loss), Net Change in Fair Value, Net of Tax	(4)	$ (1)
Other Comprehensive Income (Loss), Losses Reclassified to Income, Net of Tax	4	10
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(99)
Cash Flow Hedging [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period Start	(160)	(231)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(99)	(143)
Other Comprehensive Income (Loss), Net Change in Fair Value, Before Tax	(7)	(2)
Other Comprehensive Income (Loss), Losses Reclassified to Income, Before Tax	11	17
Other Comprehensive Income (Loss), Losses Reclassified to Income, Net of Tax	4	10
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(156)	(216)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (99)	$ (134)

Derivative and Hedging Activi76

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 515	$ 512	$ 512
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	345		381
Derivative Liability	(104)		(114)
Derivative Assets (Liabilities), at Fair Value, Net	241	267
Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	(43)		(52)
Supply Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	317		297
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] | 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] | Supply 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	246		306
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	325		372
Derivative Liability	(36)		(14)
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	(43)		(52)
Fair Value, Inputs, Level 2 [Member] | Supply 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	269		206
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	20		9
Derivative Liability	(68)		(100)
Derivative Assets (Liabilities), at Fair Value, Net	(48)	(91)	(69)	$ (54)
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] | Supply Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	317		297
Derivative Assets (Liabilities), at Fair Value, Net	$ 317	$ 297	$ 1	$ 1

Derivative and Hedging Activi77

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	$ 512
Derivative Assets (Liabilities), at Fair Value, Net, Period End	515	$ 512
Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	267
Derivative Assets (Liabilities), at Fair Value, Net, Period End	241
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 End	269	206
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	(91)	(54)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	25	78
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	18	(93)
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	(48)	(69)
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	25	78
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	21	74
Fair Value, Inputs, Level 3 [Member] | Supply Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	297	1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	33	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(13)	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	317	1
Fair Value, Inputs, Level 3 [Member] | Supply 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, Gain (Loss) Included in Earnings	20	0
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	$ 20	$ 0

Derivative and Hedging Activi78

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)
Energy Related Derivative, Oil Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	33.98%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (4)
Energy Related Derivative, Oil Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	26.58%
Energy Related Derivative, Oil Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	37.92%
Supply Contract [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	25.61%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 317
Supply Contract [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	20.72%
Supply Contract [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	43.45%
Energy Related Derivative, Natural Gas Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	32.54%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (44)
Energy Related Derivative, Natural Gas Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	19.69%
Energy Related Derivative, Natural Gas Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	47.43%

Derivative and Hedging Activi79

Derivative and Hedging Activities - Narrative (Details) € in Millions, MMBoe in Millions, $ in Millions, MMBTU in Billions	1 Months Ended		3 Months Ended
	Dec. 31, 2015USD ($)Derivatives$ / €	Dec. 31, 2006USD ($)$ / €	Mar. 31, 2016USD ($)MMBoeMMBTUcounterpartyDerivatives$ / €	Mar. 31, 2016EUR (€)MMBoecounterpartyDerivatives$ / €	Dec. 31, 2015EUR (€)Derivatives$ / €	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2006EUR (€)$ / €
Derivative [Line Items]
Number of Interest Rate Derivatives Held | Derivatives	0		0	0	0
Gain (Loss) on Repurchase of Debt Instrument			$ 100
Derivative Assets (Liabilities), at Fair Value, Net	$ 512		515			$ 512
Debt Instrument, Face Amount	9,706		9,425
Accumulated other comprehensive loss	99		99
Expected amount to be transferred of during the next 12 months			$ 21
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			6.25%	6.25%
Debt Instrument, Face Amount	329		$ 344
Cash Flow Hedging [Member]
Derivative [Line Items]
Accumulated other comprehensive loss	99		99			134	$ 143
Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative [Line Items]
Accumulated other comprehensive loss			$ 109
Interest Rate Contract [Member]
Derivative [Line Items]
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge			6 years
Deferred (Gain) Loss on Discontinuation of Fair Value Hedge			$ 7
Debt Instrument, Face Amount	$ 0		$ 0
Cross Currency Interest Rate Contract [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Debt Instrument, Repurchased Face Amount | €					€ 42
Debt Instrument, Interest Rate, Stated Percentage	6.25%		6.25%	6.25%	6.25%
Gain (Loss) on Repurchase of Debt Instrument	$ (8)
Semi Annual Interest Rate Swap Payments By Counterparty | €				€ 302				€ 9
Short-term Debt, Refinanced, Description		$ 15	$ 403
Dollar Equivalent Interest Rate		7.491%
Derivative, Forward Exchange Rate | $ / €	1.0862	1.3325	1.1380	1.1380	1.0862			1.3325
Cash paid to purchase debt	$ (8)
Foreign Exchange Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Gross Liability	(52)		$ (43)
Derivative Assets (Liabilities), at Fair Value, Net	$ (52)		$ (43)
Other Contracts, A [Member]
Derivative [Line Items]
Derivative, Number of Instruments Held | Derivatives			1	1
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			13	13
Price Risk Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe			152.5	152.5
Basis Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe			6.5	6.5
Fair Value, Inputs, Level 3 [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net			$ 269			$ 206
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contracts, A [Member]
Derivative [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives			$ 20

Oil and Natural Gas Property 80

Oil and Natural Gas Property Transactions - VPP Transactions Table (Details) Mcfe in Millions, Mcf in Millions, MBbls in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)McfeMBblsMcf	Mar. 31, 2012USD ($)McfeMBblsMcf	Jun. 30, 2011USD ($)	Dec. 31, 2008USD ($)McfeMBblsMcf	Sep. 30, 2008USD ($)	Jun. 30, 2008USD ($)	Dec. 31, 2007USD ($)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 Property 81

Oil and Natural Gas Property Transactions - VPP Volumes Produced During Period Table (Details) Mcfe in Millions, Mcf in Millions	3 Months Ended
	Mar. 31, 2016McfeMBblsMcf	Mar. 31, 2015McfeMBblsMcf
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	15.3	31.3
Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	115,500	137,600
Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	12.8	28.3
Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	312,000	373,300
VPP 10 Anadarko Basin Granite Wash [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	3.5	4.4
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	66,000	83,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	1.8	2.2
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	222,700	276,300
VPP 9 Mid-Continent [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4.1	4.5
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	39,400	43,600
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	3.4	3.7
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	89,300	97,000
VPP 8 Barnett Shale [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe		14
VPP 8 Barnett Shale [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf		14
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production		0
VPP 4 Anadarko and Arkoma Basins [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	2	2.1
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	10,100	11,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	1.9	2.1
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
VPP 3 Anadarko Basin [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	1.5	1.7
VPP 3 Anadarko Basin [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	1.5	1.7
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	0.9	1.1
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	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	0.9	1.1
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
VPP 1 Kentucky and West Virginia [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	3.3	3.5
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	3.3	3.5
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

Oil and Natural Gas Property 82

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	3 Months Ended
	Mar. 31, 2016McfeMBblsMcfMMBbls	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	227.7
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)	1.5
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	188.7
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)	4.9
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	71 months
Proved Developed Reserves (Energy) | Mcfe	53.9
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)	0.9
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	27.7
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)	3.4
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)	59 months
Proved Developed Reserves (Energy) | Mcfe	68.3
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)	0.6
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	55.7
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)	1.5
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)	9 months
Proved Developed Reserves (Energy) | Mcfe	5.6
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	5.4
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)	40 months
Proved Developed Reserves (Energy) | Mcfe	16
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	16
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)	37 months
Proved Developed Reserves (Energy) | Mcfe	8.9
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	8.9
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)	81 months
Proved Developed Reserves (Energy) | Mcfe	75
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	75
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 Property 83

Oil and Natural Gas Property Transactions - Narrative (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	$ 62,000,000	$ 21,000,000
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Property, Plant, and Equipment	78,000,000
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	140,000,000	$ 21,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets	$ 0

Variable Interest Entities - Na

Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Variable Interest Entity [Line Items]
Noncontrolling interests	$ 260		$ 259
Net income attributable to noncontrolling interests	0	$ 19
VIE, Cash and cash equivalents	16	2,907	825	$ 4,108
VIE. proved natural gas and oil properties	64,305		63,843
VIE. accumulated depreciation, depletion and amortization	(60,506)		(59,365)
VIE. other current liabilities	1,544		2,219
Proceeds from sales ro KKR	62	21
Loss on sale of investment	(10)	0
Mineral Acquisition Company I, L.P. [Member]
Variable Interest Entity [Line Items]
VIE, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net			10
Proceeds from sales ro KKR	9
Loss on sale of investment	(10)
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Variable Interest Entity [Line Items]
Noncontrolling interests	260	259
Net income attributable to noncontrolling interests	0	$ 1
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	(445)		(428)
VIE. other current liabilities	$ 2		$ 8

Impairments Impairments - Fixed

Impairments Impairments - Fixed Assets and Other Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	$ 38	$ 4
Compressor [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	20	0
Buildings and land [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	7	0
Other [Member]
Property, Plant and Equipment [Line Items]
Impairments of fixed assets and other	$ 11	$ 4

Impairments - Narrative (Detail

Impairments - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Asset Impairment Charges [Abstract]
Impairment of oil and natural gas properties	$ 853	$ 4,976
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	$ 166	$ 195

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	$ (2)	$ (1)
Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	48	50
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(50)	(51)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	(2)	(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	48	50
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	(50)	(51)
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

Segment Information - Table (De

Segment Information - Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Total Revenues	$ 1,953	$ 3,218
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(921)	(5,092)
TOTAL ASSETS	15,357		$ 17,314
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	993	1,543
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	960	1,675
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	1,953	3,218
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	993	1,520
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(895)	(5,349)
TOTAL ASSETS	12,624		14,610
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member] | Scenario, Previously Reported [Member]
Segment Reporting Information [Line Items]
TOTAL ASSETS			11,776
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	1,743	2,908
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	40	4
TOTAL ASSETS	1,425		1,524
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(9)	(14)
TOTAL ASSETS	1,468		1,491
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member] | Scenario, Previously Reported [Member]
Segment Reporting Information [Line Items]
TOTAL ASSETS			4,325
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(783)	0
Intersegment Eliminations [Member] | Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	(1,210)
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	783	1,210
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(57)	267
TOTAL ASSETS	(160)		$ (311)
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	23
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	(783)	(1,233)
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ 0

Segment Information - Narrative

Segment Information - Narrative (Details) $ in Millions	3 Months Ended
	Mar. 31, 2016USD ($)Segment	Mar. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	2
Total Revenues	$ 1,953	$ 3,218
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(783)	0
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	960	1,675
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0
Intersubsegment Eliminations [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	783	1,210
Intersubsegment Eliminations [Member] | Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ (783)	$ (1,233)

Condensed Consolidating Finan90

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Mar. 31, 2016
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) $ in Millions	May. 04, 2016USD ($)a	Mar. 31, 2016USD ($)	Mar. 31, 2015USD ($)
Subsequent Event [Line Items]
Proceeds from divestitures of proved and unproved properties		$ 62	$ 21
STACK Play [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Number Of Net Acres | a	42,000
Proceeds from divestitures of proved and unproved properties	$ 470