Expand Energy (EXE) 10-Q 4 Nov 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Oct. 29, 2015
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
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		665,070,706

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 1,759	$ 4,108
Restricted cash	0	38
Accounts receivable, net	1,275	2,236
Short-term derivative assets ($0 and $16 attributable to our VIE)	342	879
Other current assets	203	207
Total Current Assets	3,579	7,468
Oil and natural gas properties, at cost based on full cost accounting:
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	62,941	58,594
Unproved properties	7,185	9,788
Other property and equipment	2,935	3,083
Total Property and Equipment, at Cost	73,061	71,465
Less: accumulated depreciation, depletion and amortization (($397) and ($251) attributable to our VIE)	(56,196)	(39,043)
Property and equipment held for sale, net	94	93
Total Property and Equipment, Net	16,959	32,515
LONG-TERM ASSETS:
Investments	225	265
Long-term derivative assets	257	6
Other long-term assets	266	497
TOTAL ASSETS	21,286	40,751
CURRENT LIABILITIES:
Accounts payable	1,070	2,049
Current maturities of long-term debt, net	893	381
Accrued interest	137	150
Deferred income tax liabilities	59	207
Short-term derivative liabilities	24	15
Other current liabilities ($11 and $15 attributable to our VIE)	2,374	3,061
Total Current Liabilities	4,557	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	10,674	11,154
Deferred income tax liabilities	574	4,185
Long-term derivative liabilities	106	218
Asset retirement obligations, net of current portion	442	447
Other long-term liabilities	387	679
Total Long-Term Liabilities	12,183	16,683
Chesapeake Stockholders’ Equity:
Preferred stock, $0.01 par value, 20,000,000 shares authorized: 7,251,515 shares outstanding	3,062	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized: 665,042,789 and 664,944,232 shares issued	7	7
Paid-in capital	12,385	12,531
Retained earnings (accumulated deficit)	(11,017)	1,483
Accumulated other comprehensive loss	(119)	(143)
Less: treasury stock, at cost; 1,570,895 and 1,614,312 common shares	(36)	(37)
Total Chesapeake Stockholders’ Equity	4,282	16,903
Noncontrolling interests	264	1,302
Total Equity	4,546	18,205
TOTAL LIABILITIES AND EQUITY	$ 21,286	$ 40,751

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Preferred stock, par value (usd per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized (shares)	20,000,000	20,000,000
Preferred stock, shares outstanding (shares)	7,251,515	7,251,515
Common stock, par value (usd per share)	$ 0.01	$ 0.01
Common Stock, Shares Authorized	1,000,000,000	1,000,000,000
Common Stock, Shares, Issued	665,042,789	664,944,232
Treasury stock, shares	1,570,895	1,614,312
Cash and cash equivalents	$ 1,759	$ 4,108
Short-term derivative assets ($0 and $16 attributable to our VIE)	342	879
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	62,941	58,594
Less: accumulated depreciation, depletion and amortization (($397) and ($251) attributable to our VIE)	(56,196)	(39,043)
Other current liabilities ($11 and $15 attributable to our VIE)	2,374	3,061
Variable Interest Entities, Primary Beneficiary [Member]
Cash and cash equivalents	1	1
Short-term derivative assets ($0 and $16 attributable to our VIE)	0	16
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($397) and ($251) attributable to our VIE)	(397)	(251)
Other current liabilities ($11 and $15 attributable to our VIE)	$ 11	$ 15

CONDENSED CONSOLIDATED STATEMEN

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES:
Oil, natural gas and NGL	$ 880	$ 2,341	$ 2,693	$ 5,812
Marketing, gathering and compression	2,013	3,362	5,993	9,543
Oilfield services	0	0	0	546
Total Revenues	2,893	5,703	8,686	15,901
OPERATING EXPENSES:
Oil, natural gas and NGL production	251	298	826	868
Production taxes	25	62	87	185
Marketing, gathering and compression	1,955	3,369	5,751	9,515
Oilfield services	0	0	0	431
General and administrative	49	60	174	229
Restructuring and other termination costs	53	(14)	39	12
Provision for legal contingencies	0	100	359	100
Oil, natural gas and NGL depreciation, depletion and amortization	488	688	1,773	1,977
Depreciation and amortization of other assets	31	37	100	194
Impairment of oil and natural gas properties	5,416	0	15,407	0
Impairments of fixed assets and other	79	15	167	75
Net (gains) losses on sales of fixed assets	(1)	(86)	3	(201)
Total Operating Expenses	8,346	4,529	24,686	13,385
INCOME (LOSS) FROM OPERATIONS	(5,453)	1,174	(16,000)	2,516
OTHER INCOME (EXPENSE):
Interest expense	(88)	(17)	(210)	(82)
Losses on investments	(33)	(27)	(57)	(72)
Net gain on sales of investments	0	0	0	67
Losses on purchases of debt	0	0	0	(195)
Other income (expense)	(2)	(1)	3	12
Total Other Expense	(123)	(45)	(264)	(270)
INCOME (LOSS) BEFORE INCOME TAXES	(5,576)	1,129	(16,264)	2,246
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	0	2	(6)	10
Deferred income taxes	(937)	435	(3,808)	849
Total Income Tax Expense (Benefit)	(937)	437	(3,814)	859
NET INCOME (LOSS)	(4,639)	692	(12,450)	1,387
Net income attributable to noncontrolling interests	(13)	(30)	(50)	(110)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(4,652)	662	(12,500)	1,277
Preferred stock dividends	(43)	(43)	(128)	(128)
Repurchase of preferred shares of CHK Utica	0	(447)	0	(447)
Earnings allocated to participating securities	0	(3)	0	(15)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (4,695)	$ 169	$ (12,628)	$ 687
EARNINGS (LOSS) PER COMMON SHARE:
Earnings Per Share, Basic	$ (7.08)	$ 0.26	$ (19.07)	$ 1.04
Earnings Per Share, Diluted	(7.08)	0.26	(19.07)	1.04
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0	$ 0.0875	$ 0.0875	$ 0.2625
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	663	660	662	659
Weighted Average Number of Shares Outstanding, Diluted	663	660	662	659

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
NET INCOME (LOSS)	$ (4,639)	$ 692	$ (12,450)	$ 1,387
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $5, $0, $4 and $3	7	0	6	3
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $2, $11 and $12	5	3	18	13
Reclassification of (gains) losses on investment, net of income tax expense (benefit) of $0, $0, $0 and ($3)	0	0	0	(5)
Other Comprehensive Income (Loss)	12	3	24	11
COMPREHENSIVE INCOME (LOSS)	(4,627)	695	(12,426)	1,398
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(13)	(30)	(50)	(110)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ (4,640)	$ 665	$ (12,476)	$ 1,288

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $5, $0, $4 and $3	$ 5	$ 0	$ 4	$ 3
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	2	2	11	12
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	$ 0	$ 0	$ 0	$ (3)

CONDENSED CONSOLIDATED STATEME7

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ (12,450)	$ 1,387
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,873	2,171
Deferred income tax expense (benefit)	(3,808)	849
Derivative gains, net	(642)	(20)
Cash receipts (payments) on derivative settlements, net	850	(341)
Stock-based compensation	61	59
Impairment of oil and natural gas properties	15,407	0
Net (gains) losses on sales of fixed assets	3	(201)
Impairments of fixed assets and other	159	44
Losses on investments	57	72
Net gains on sales of investments	0	(67)
Losses on purchases of debt	0	61
Restructuring and other termination costs	39	(18)
Provision for legal contingencies	359	100
Other	24	57
Changes in assets and liabilities	(877)	(348)
Net Cash Provided By Operating Activities	1,055	3,805
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,696)	(3,185)
Acquisitions of proved and unproved properties	(407)	(1,023)
Proceeds from divestitures of proved and unproved properties	188	723
Additions to other property and equipment	(114)	(675)
Proceeds from sales of other property and equipment	80	964
Additions to investments	(8)	(14)
Proceeds from sales of investments	0	239
Decrease in restricted cash	52	37
Other	0	(4)
Net Cash Used In Investing Activities	(2,905)	(2,938)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	3,573
Payments on credit facilities borrowings	0	(3,896)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	394
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	(3,362)
Cash paid for common stock dividends	(118)	(175)
Cash paid for preferred stock dividends	(128)	(128)
Cash paid on financing derivatives	0	(50)
Cash held at deconsolidation	(143)
Cash paid to repurchase preferred shares of CHK Utica	0	(1,254)
Distributions to noncontrolling interest owners	(78)	(143)
Other	(32)	(25)
Net Cash Used In Financing Activities	(499)	(1,614)
Net decrease in cash and cash equivalents	(2,349)	(747)
Cash and cash equivalents, beginning of period	4,108	837
Cash and cash equivalents, end of period	1,759	90
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	134	88
Income taxes paid, net of refunds received	50	17
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Repurchase of noncontrolling interest, Non-Cash Investing and Financing Activities	(872)	0
Change in Divested Proved and Unproved properties, Non-Cash Investing and Financing Activities	1,046	23
Change in accrued drilling and completion costs	(124)	(64)
Change in accrued acquisitions of proved and unproved properties	61	(100)
Chesapeake Energy [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	0	2,966
Chesapeake Oilfield Operating [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of senior notes, net of discount and offering costs	0	494
Cash held at deconsolidation	$ 0	(8)
Utica [Member]
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash held at deconsolidation		$ 0

CONDENSED CONSOLIDATED STATEME8

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($) $ in Millions	Total	Preferred Stock [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2013				$ 12,446	$ 688	$ (162)	$ (46)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				26
Exercise of stock options				24
Dividends on common stock				0	(175)
Dividends on preferred stock				0	(128)
Decrease in tax benefit from stock-based compensation				(1)
Net income (loss) attributable to Chesapeake	$ 1,277				1,277
Spin-off of oilfield services business	(270)				(270)
Repurchase of preferred shares of CHK Utica	(447)
Hedging activity						16
Investment activity						(5)
Purchase of 37,687 and 24,859 shares for company benefit plans							(1)
Release of 81,104 and 369,432 shares from company benefit plans							9
Chesapeake stockholders’ equity, end of period at Sep. 30, 2014		$ 3,062	$ 7	12,495	945	(151)	(38)	$ 16,320
Stockholders' Equity Attributable to Noncontrolling Interest, Beginning of Period at Dec. 31, 2013									$ 2,145
Increase (Decrease) in Stockholders' Equity [Roll Forward]
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(110)								110
Distributions to noncontrolling interest owners									(137)
Repurchase of noncontrolling interest of CHK C-T									0
Repurchase of preferred shares of CHK Utica									(807)
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Sep. 30, 2014									1,311
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	17,631
TOTAL EQUITY	18,205
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2014	16,903			12,531	1,483	(143)	(37)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Stock-based compensation				52
Exercise of stock options				0
Dividends on common stock				(59)	0
Dividends on preferred stock				(128)	0
Decrease in tax benefit from stock-based compensation				(11)
Net income (loss) attributable to Chesapeake	(12,500)				(12,500)
Spin-off of oilfield services business					0
Repurchase of preferred shares of CHK Utica	0
Hedging activity						24
Investment activity						0
Purchase of 37,687 and 24,859 shares for company benefit plans							(1)
Release of 81,104 and 369,432 shares from company benefit plans							2
Chesapeake stockholders’ equity, end of period at Sep. 30, 2015	4,282	$ 3,062	$ 7	$ 12,385	$ (11,017)	$ (119)	$ (36)	$ 4,282
Stockholders' Equity Attributable to Noncontrolling Interest, Beginning of Period at Dec. 31, 2014	1,302								1,302
Increase (Decrease) in Stockholders' Equity [Roll Forward]
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(50)								50
Distributions to noncontrolling interest owners									(73)
Repurchase of noncontrolling interest of CHK C-T									(1,015)
Repurchase of preferred shares of CHK Utica									0
Stockholders' Equity Attributable to Noncontrolling Interest, End of Period at Sep. 30, 2015	264								$ 264
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	$ 4,546

CONDENSED CONSOLIDATED STATEME9

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - Treasury Stock - Common [Member] - shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Purchase of shares for company benefit plans, shares	37,687	24,859
Release of shares from company benefit plans, shares	81,104	369,432

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies (Note)	9 Months Ended
	Sep. 30, 2015
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 and nine months ended September 30, 2015 (the "Current Quarter" and the “Current Period”, respectively) and the three and nine months ended September 30, 2014 (the "Prior Quarter" and the “Prior Period”, respectively). Chesapeake's annual report on Form 10-K for the year ended December 31, 2014 ("2014 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 and the Current Period are not necessarily indicative of the results to be expected for the full year.

Earnings Per Share (Note)

Earnings Per Share (Note)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Earnings Per Share Disclosure	Earnings Per Share Basic earnings per share (EPS) is calculated using the weighted average number of common shares outstanding during the period and includes the effect of any participating securities as appropriate. Participating securities consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights. Diluted EPS is calculated assuming the issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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, the Prior Quarter, the Current Period and the Prior Period, 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 September 30, 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 Three Months Ended September 30, 2014 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 $ 3 3 Nine Months Ended September 30, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 64 59 5.75% cumulative convertible preferred stock (series A) $ 47 42 5.00% cumulative convertible preferred stock (series 2005B) $ 8 6 4.50% cumulative convertible preferred stock $ 9 6 Participating securities $ — 1 Nine Months Ended September 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 64 59 5.75% cumulative convertible preferred stock (series A) $ 47 42 5.00% cumulative convertible preferred stock (series 2005B) $ 8 6 4.50% cumulative convertible preferred stock $ 9 6 Participating securities $ 14 3

Debt (Note)

Debt (Note)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Debt Disclosure	Debt Our long-term debt consisted of the following as of September 30, 2015 and December 31, 2014: September 30, December 31, ($ in millions) 3.25% senior notes due 2016 $ 500 $ 500 6.25% euro-denominated senior notes due 2017 (a) 384 416 6.5% senior notes due 2017 660 660 7.25% senior notes due 2018 669 669 Floating rate senior notes due 2019 1,500 1,500 6.625% senior notes due 2020 1,300 1,300 6.875% senior notes due 2020 500 500 6.125% senior notes due 2021 1,000 1,000 5.375% senior notes due 2021 700 700 4.875% senior notes due 2022 1,500 1,500 5.75% senior notes due 2023 1,100 1,100 2.75% contingent convertible senior notes due 2035 (b) 396 396 2.5% contingent convertible senior notes due 2037 (b) 1,168 1,168 2.25% contingent convertible senior notes due 2038 (b) 347 347 Revolving credit facility — — Discount on senior notes (c) (165 ) (231 ) Interest rate derivatives (d) 8 10 Total debt, net 11,567 11,535 Less current maturities of long-term debt, net (e) (893 ) (381 ) Total long-term debt, net $ 10,674 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.1177 to €1.00 and $1.2098 to €1.00 as of September 30, 2015 and December 31, 2014, 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. The first put date, for the 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), is November 15, 2015. As required by the terms of the indenture for the 2035 Notes, on October 1, 2015, we issued a notice to the holders of the 2035 Notes allowing each holder an opportunity to require us to repurchase some or all of its notes on November 15, 2015. As a result, we may be required to repurchase some or all of the 2035 Notes outstanding on November 15, 2015. 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 third quarter of 2015, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2015 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 or 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, 2015, 2020, 2025, 2030 $ 45.14 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 $ 100.35 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. Beginning December 1, 2015, we may redeem any 2035 Notes that have not been put to us and repurchased as described above under Holders’ Demand Repurchase Rights . (c) Discount as of September 30, 2015 and December 31, 2014 included $160 million and $224 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (d) See Interest Rate Derivatives in Note 8 for further discussion related to these instruments. (e) As of September 30, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016 and 2035 Notes. As discussed in footnote (b) above, the holders of our 2035 Notes could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes. As of September 30, 2015 and December 31, 2014, current maturities of long-term debt, net reflects $3 million and $15 million , respectively, of discount associated with the equity component of the 2035 Notes. Chesapeake Senior Notes and Contingent Convertible Senior Notes The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. As a holding company, Chesapeake owns no operating assets and has no significant operations independent of its subsidiaries. Chesapeake’s obligations under the senior notes and the contingent convertible senior notes are jointly and severally, fully and unconditionally guaranteed by certain of our direct and indirect 100% owned subsidiaries. See Note 19 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries. We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale-leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. Indentures for the senior notes and contingent convertible senior notes have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million or $75 million , depending on the indenture. We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86% , 8.0% and 8.0% , respectively. In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York against The Bank of New York Mellon Trust Company, N.A., the indenture trustee for the 6.775% Senior Notes due 2019 (the 2019 Notes). The Company sought and ultimately obtained a judgment declaring that the notice it issued on March 15, 2013 to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective for that redemption pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. In May 2013, as a result of that ruling, the 2019 Notes were redeemed at par. In November 2014, the U.S. Court of Appeals for the Second Circuit, on appeal by the indenture trustee, reversed the District Court’s declaratory judgment and held that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose. The Court of Appeals remanded the case to the District Court for a determination whether the redemption notice triggered a redemption at the make-whole price specified in the indenture, instead of at par. The Company sought a rehearing by the Court of Appeals en banc in December 2014, and that petition was denied on February 6, 2015. On February 13, 2015, the indenture trustee moved the District Court for entry of a judgment requiring the Company to pay the make-whole price, as defined in the indenture, less the par amount paid in the 2013 redemption plus prejudgment interest from the redemption date. On March 20, 2015, the Company filed its opposition to the Trustee’s motion and cross-moved for a judgment requiring the Company to pay restitution in an amount that would disgorge the benefit the Company achieved from refinancing the 2019 Notes in 2013 and that would return the parties to the economic positions they would have been in if the par redemption had never taken place. On July 10, 2015, the District Court granted the Trustee’s motion and denied the Company’s cross-motion and entered an amended judgment on July 17, 2015 awarding the Trustee $380 million plus prejudgment interest in the amount of $59 million . The Company filed a notice of appeal on July 27, 2015 and posted a supersedeas bond to stay execution of the judgment while appellate proceedings are pending. Revolving Credit Facility On September 30, 2015, we entered into an amendment to our $4.0 billion senior revolving credit facility dated December 15, 2014 and maturing December 2019, which is used for general corporate purposes. Pursuant to the amended credit agreement, we are required to secure our obligations under the facility and certain hedging agreements with liens on certain of our oil and natural gas properties, with such liens to be released upon the satisfaction of specific conditions. The amended credit facility provides that, while the obligations are required to be secured, (i) we have the right to incur junior lien indebtedness of up to $2.0 billion; (ii) our use of the facility will be subject to a borrowing base; (iii) the rate of interest on outstanding loans, as well as fees on undrawn commitments, will vary based on the percentage of the borrowing base used, rather than on our credit ratings; (iv) the total leverage ratio covenant will be suspended; and (v) the credit facility will be subject to a first lien secured leverage ratio and an interest rate coverage ratio (as described below). The amendment sets the borrowing base at $4.0 billion. The total commitments under the credit facility remain at $4.0 billion, subject to reduction in connection with issuances of junior lien indebtedness by us after April 15, 2016, the date of the first borrowing base redetermination. No adjustment to the total commitment will occur for any junior lien indebtedness issuance that occurs before April 15, 2016. As of September 30, 2015 , we had no outstanding borrowings under the facility and had used $12 million of the facility for various letters of credit. While obligations under our credit facility are required to be secured, revolving loans under the amended credit facility will bear interest, at our election, at either (i) a fluctuating rate per annum equal to the highest of (a) the federal funds effective rate plus 0.5% , (b) the administrative agent’s prime rate or (c) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), or (ii) a LIBOR rate (LIBOR loans), in each case plus a margin based on the percentage of the borrowing base used (currently 1.0% per annum for ABR loans and 2.0% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, our ability to incur additional indebtedness, make investments or loans, create liens, consummate mergers and similar fundamental changes, make restricted payments, make investments in unrestricted subsidiaries and enter into transactions with affiliates, together with a requirement that we maintain, as of the last day of each fiscal quarter, a net debt to capitalization ratio (as defined in the amended credit agreement) that does not exceed 65%. While it is required to be secured by a portion of our oil and natural gas properties, the amended credit facility requires us to maintain, as of the last day of each fiscal quarter (i) a first lien secured leverage ratio (as defined in the amended credit agreement) of 3.5 to 1.0 through 2017 and 3.0 to 1.0 thereafter, and (ii) an interest rate coverage ratio (as defined in the amended credit agreement) of 1.1 to 1.0 through the first quarter of 2017, increasing to 1.25 to 1.0 by the end of 2017. Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The amended credit agreement includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; incorrectness of representations and warranties in any material respect; cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more ; bankruptcy; judgments involving liability of $125 million or more that are not paid ; and ERISA events . Many events of default are subject to customary notice and cure periods. Spin-Off Debt Transactions On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary Chesapeake Oilfield Operating, L.L.C. (COO), into the independent, publicly traded company Seventy Seven Energy Inc. (SSE). In the Prior Period, COO or its subsidiaries completed the following debt transactions: • Entered into a five -year senior secured revolving credit facility with total commitments of $275 million and incurred approximately $3 million in financing costs related to entering into the facility. • Entered into a $400 million seven -year secured term loan and used the net proceeds of approximately $394 million and borrowings under the new revolving credit facility to repay and terminate COO’s then-existing credit facility. • Issued $500 million in aggregate principal amount of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds of approximately $494 million to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes. All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 15 for further discussion of the spin-off. Fair Value of Debt We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which would include borrowings under our revolving credit facility (which was undrawn as of September 30, 2015 and December 31, 2014), is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. September 30, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 893 $ 881 $ 381 $ 396 Long-term debt (Level 1) $ 10,666 $ 8,043 $ 11,144 $ 11,656

Contingencies and Commitments (

Contingencies and Commitments (Note)	9 Months Ended
	Sep. 30, 2015
Commitments and Contingencies Disclosure [Abstract]
Legal Matters and Contingencies	Contingencies Litigation and Regulatory Proceedings The Company is involved in a number of litigation and regulatory proceedings (including those described below). Many of these proceedings are in early stages, and many of them seek or may seek damages and penalties, the amount of which is indeterminate. We estimate and provide for potential losses that may arise out of litigation and regulatory proceedings to the extent that such losses are probable and can be reasonably estimated. Significant judgment is required in making these estimates and our final liabilities may ultimately be materially different. Our total estimated liability in respect of litigation and regulatory proceedings is determined on a case-by-case basis and represents an estimate of probable losses after considering, among other factors, the progress of each case or proceeding, our experience and the experience of others in similar cases or proceedings, and the opinions and views of legal counsel. We account for legal defense costs in the period the costs are incurred. July 2008 Common Stock Offering Litigation. On February 25, 2009, a putative class action was filed in the U.S. District Court for the Southern District of New York against the Company and certain of its officers and directors along with certain underwriters of the Company’s July 2008 common stock offering. The plaintiffs filed an amended complaint on September 11, 2009 alleging that the registration statement for the offering contained material misstatements and omissions and seeking damages under Sections 11, 12 and 15 of the Securities Act of 1933 of an unspecified amount and rescission. The action was transferred to the U.S. District Court for the Western District of Oklahoma on October 13, 2009. Chesapeake and the officer and director defendants moved for summary judgment on grounds of loss causation and materiality on December 28, 2011, and the motion was granted as to all claims as a matter of law on March 29, 2013. On appeal, the U.S. Court of Appeals for the Tenth Circuit affirmed the dismissal on August 8, 2014 and denied the plaintiffs’ petition for rehearing on November 12, 2014. On April 10, 2015, the plaintiffs filed a writ of certiorari with the United States Supreme Court, and on October 15, 2015, certiorari was denied and the case was closed. Shareholder Derivative Litigation. A federal consolidated derivative action and an Oklahoma state court derivative action were stayed in 2012 pending resolution of a related, previously reported putative federal securities class action. The shareholder derivative actions alleged breaches of fiduciary duty, among other things, related to the former CEO’s personal financial practices and purported conflicts of interest, and the Company’s accounting for volumetric production payments. The federal securities class action was dismissed in July 2014, and the parties stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursued their claims in the federal consolidated derivative action. The plaintiffs filed a consolidated derivative complaint on October 31, 2014 and an amended consolidated derivative complaint on February 12, 2015. Chesapeake filed its motion to dismiss on February 23, 2015, and on August 13, 2015, the plaintiffs filed a notice of voluntary dismissal. The federal derivative case was dismissed on September 29, 2015, and the Oklahoma state derivative case was dismissed on August 21, 2015. 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 gas rights in various states. The Company also has received DOJ, the U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake has engaged in discussions with the DOJ and state agency representatives and continues to respond to such subpoenas and demands. Redemption of 2019 Notes. See Note 3 for a description of pending litigation regarding our redemption in May 2013 of our 2019 Notes. As a result of the reversal of the trial court’s decision in our declaratory judgment action against the indenture trustee, we accrued a loss contingency of $100 million for this matter in the 2014 fourth quarter, and we accrued an additional $339 million in the Current Period as a result of the judgment on remand entered on July 17, 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 natural gas liquids (NGL). Plaintiffs have varying royalty provisions in their respective leases, oil and gas law varies from state to state, and royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations. The Company has resolved a number of these claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits. We are currently defending lawsuits seeking damages with respect to royalty underpayment in various states, including, but not limited to, Texas, Pennsylvania, Ohio, Oklahoma, Louisiana and Arkansas. These lawsuits include cases filed by individual royalty owners and putative class actions, some of which seek to certify a statewide class. The Company also has received DOJ, U.S. Postal Service and state subpoenas seeking information on the Company’s royalty payment practices. Chesapeake is defending numerous lawsuits filed by individual royalty owners alleging royalty underpayment with respect to properties in Texas. On April 8, 2015, Chesapeake obtained a transfer order from the Texas Multidistrict Litigation Panel to transfer a substantial portion of these lawsuits filed since June 2014 to the 348th District Court of Tarrant County for pre-trial purposes. These lawsuits, which primarily relate to the Barnett Shale, generally allege that Chesapeake underpaid royalties by making improper deductions and using incorrect production volumes. In addition to allegations of breach of contract, a number of these lawsuits allege fraud, conspiracy, joint venture and antitrust violations by Chesapeake. Chesapeake expects that additional lawsuits will be filed by new plaintiffs making similar allegations. The lawsuits seek direct damages in varying amounts, together with exemplary damages, attorneys’ fees, costs and interest. Chesapeake believes its royalty calculations and payment practices were appropriate and has not accrued a loss contingency with respect to the multidistrict litigation. 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. 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 other pending royalty cases for which we have not accrued a loss contingency, but we are currently unable to estimate an amount or range of loss or the impact the actions could have on our future results of operations or cash flows. Uncertainties in pending royalty cases generally include the complex nature of the claims and defenses, the potential size of the class in class actions, the scope and types of the properties and agreements involved, and the applicable production years. Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its future consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates. Environmental Contingencies The nature of the oil and gas business carries with it certain environmental risks for Chesapeake and its subsidiaries. Chesapeake has implemented various policies, procedures, training and auditing to reduce and mitigate such environmental risks. Chesapeake conducts periodic reviews, on a company-wide basis, to assess changes in our environmental risk profile. Environmental reserves are established for environmental liabilities for which economic losses are probable and reasonably estimable. We manage our exposure to environmental liabilities in acquisitions by using an evaluation process that seeks to identify pre-existing contamination or compliance concerns and address the potential liability. Depending on the extent of an identified environmental concern, Chesapeake may, among other things, exclude a property from the transaction, require the seller to remediate the property to our satisfaction in an acquisition or agree to assume liability for the remediation of the property
Commitments Contingencies and Guarantees	Commitments Gathering, Processing and Transportation Agreements We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids 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. September 30, ($ in millions) 2015 $ 461 2016 1,927 2017 1,939 2018 1,741 2019 1,452 2020 – 2099 6,828 Total $ 14,348 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, including those entered into with SSE in connection with the spin-off of our oilfield services business in June 2014, 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 September 30, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $321 million . Pressure Pumping Contracts In connection with the spin-off of our oilfield services business in June 2014, we entered into an agreement with a subsidiary of SSE for pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven , five and three pressure pumping crews in years one , two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. As of September 30, 2015 , the aggregate undiscounted minimum future payments under this agreement were approximately $265 million . Drilling Commitments We have committed to drill wells for the benefit of Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 6 for discussion of this commitment. Oil, Natural Gas and NGL Purchase Commitments We commit to purchase oil, natural gas and NGL from other owners in the properties we operate, including owners associated with our volumetric production payment (VPP) transactions. Production purchases under these arrangements are based on market prices at the time of production, and the purchased oil, natural gas and NGL are resold at market prices. See Volumetric Production Payments in Note 9 for further discussion of our VPP transactions. Net Acreage Maintenance Commitments Under the terms of our Barnett and Utica Shale joint venture agreements with Total S.A. (see Joint Ventures in Note 9), we are required to extend, renew or replace expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas as of future measurement dates. In the Current Quarter, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge, which is included in impairments of fixed assets and other in our condensed consolidated statement of operations. Other Commitments In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc. (Sundrop), a privately held cellulosic biofuels company based in Longmont, Colorado. We also provided Sundrop with a one-time option to require us to purchase up to $25 million in additional preferred equity securities following the full payment of the initial investment. To date, we have funded our $155 million commitment in full and Sundrop has not exercised its preferred equity call option. See Note 10 for further discussion of this investment. As part of our normal course of business, we enter into various agreements providing, or otherwise arranging for, financial or performance assurances to third parties on behalf of our wholly owned guarantor subsidiaries. These agreements may include future payment obligations or commitments regarding operational performance that effectively guarantee our subsidiaries’ future performance. In connection with divestitures, our purchase and sale agreements generally provide indemnification to the counterparty for liabilities incurred as a result of a breach of a representation or warranty by the indemnifying party and/or other specified matters. These indemnifications generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or cannot be quantified at the time of entering into or consummating a particular transaction. For divestitures of oil and 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, restructuring and other termination costs, 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)	9 Months Ended
	Sep. 30, 2015
Other Liabilities Disclosure [Abstract]
Other Liabilities Disclosure	Other Liabilities Other current liabilities as of September 30, 2015 and December 31, 2014 are detailed below. September 30, December 31, ($ in millions) Revenues and royalties due others $ 627 $ 1,176 Accrued drilling and production costs 231 385 Joint interest prepayments received 181 189 Accrued compensation and benefits 295 344 Other accrued taxes 105 55 Accrued dividends 43 101 Bank of New York Mellon legal accrual 439 100 Royalty settlement — 119 Other 453 592 Total other current liabilities $ 2,374 $ 3,061 Other long-term liabilities as of September 30, 2015 and December 31, 2014 are detailed below. September 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 198 $ 220 CHK C-T ORRI conveyance obligation (b) — 135 Financing obligations 29 30 Unrecognized tax benefits 25 45 Other 135 249 Total other long-term liabilities $ 387 $ 679 ____________________________________________ (a) $20 million and $14 million of the total $218 million and $234 million obligations are recorded in other current liabilities as of September 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation. (b) $23 million of the total $158 million obligation is recorded in other current liabilities as of December 31, 2014. In the Current Quarter, we sold the oil and natural gas properties held by CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and eliminated our ORRI obligation attributable to CHK C-T. See Noncontrolling Interests in Note 6 for further discussion of the transaction.

Equity (Note)

Equity (Note)	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Stockholders' Equity Note Disclosure	Equity Common Stock The following is a summary of the changes in our common shares issued for the Current Period and the Prior Period: Nine Months Ended 2015 2014 (in thousands) Shares issued as of January 1 664,944 666,192 Restricted stock issuances (net of forfeitures and cancellations) (a) 85 (2,413 ) Stock option exercises 14 1,267 Shares issued as of September 30 665,043 665,046 ___________________________________________ (a) The Prior Period reflects forfeitures upon the June 2014 spin-off of our oilfield services business. Preferred Stock The following reflects the shares outstanding of our preferred stock for the Current Period and the Prior Period: 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2015 and 2014 and shares outstanding as of September 30, 2015 and 2014 1,497 1,100 2,559 2,096 Dividends Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings exists after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, dividend declarations are accounted for as a reduction to paid-in capital. In July 2015, our Board of Directors determined to eliminate quarterly cash dividends on our common stock. Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash. Accumulated Other Comprehensive Income (Loss) For the Current Period and the Prior Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Investments Net Change ($ in millions) Balance, December 31, 2014 $ (143 ) $ — $ (143 ) Other comprehensive income before reclassifications 6 — 6 Amounts reclassified from accumulated other comprehensive income 18 — 18 Net other comprehensive income 24 — 24 Balance, September 30, 2015 $ (119 ) $ — $ (119 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 3 — 3 Amounts reclassified from accumulated other comprehensive income 13 (5 ) 8 Net other comprehensive income 16 (5 ) 11 Balance, September 30, 2014 $ (151 ) $ — $ (151 ) For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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 September 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 5 Total reclassifications for the period, net of tax $ 5 Three Months Ended September 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 3 Total reclassifications for the period, net of tax $ 3 Nine Months Ended September 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 18 Total reclassifications for the period, net of tax $ 18 Nine Months Ended September 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 13 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 8 Noncontrolling Interests Cleveland Tonkawa Financial Transaction. We formed CHK C-T in March 2012 to continue development of a portion of our oil and natural gas assets in our Cleveland and Tonkawa plays. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum cumulative total of 300 net wells. We ultimately drilled and completed 190 net wells, and the drilling commitment was suspended in January 2015. In the Current Quarter, CHK C-T sold all of its oil and natural gas properties to FourPoint Energy, LLC (FourPoint) and immediately used the consideration received, plus other cash it had on hand, to repurchase and cancel all of the outstanding preferred shares in CHK C-T. Chesapeake is responsible for post-closing adjustments to the purchase price and has certain indemnity obligations in connection with the sale to FourPoint. In connection with the repurchase and cancellation of the CHK C-T preferred stock and related agreements with the CHK C-T investors, we eliminated quarterly preferred dividend payments and all related future drilling and ORRI commitments attributable to CHK C-T. Under the full cost method of accounting, the sale of the oil and natural gas properties was accounted for as a reduction of capitalized costs with no gain or loss recognized. As of December 31, 2014 , $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK C-T. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of $13 million , $19 million , $50 million and $56 million , respectively, was attributable to the noncontrolling interests of CHK C-T. Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale oil and natural gas assets. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold. In July 2014, we repurchased all of the outstanding preferred shares of CHK Utica from third-party preferred shareholders for approximately $1.254 billion , or approximately $1,189 per share including accrued dividends. The $447 million difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired was reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations. Pursuant to the transaction, our obligation to pay quarterly dividends to third-party preferred shareholders was eliminated. In addition, the development agreement was terminated pursuant to the transaction, which eliminated our obligation to drill and complete a minimum number of wells within a specified period for the benefit of CHK Utica. Our repurchase of the outstanding preferred shares in CHK Utica did not affect our obligation to deliver a 3% ORRI in 1,500 net wells on certain Utica Shale leasehold. The CHK Utica investors’ right to receive, proportionately, a 3% ORRI in the first 1,500 net wells drilled on our Utica Shale leasehold is subject to an increase to 4% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation, which runs through 2023. However, in no event are we required to deliver to investors more than a total ORRI of 3% in 1,500 net wells. If at any time we hold fewer net acres than would enable us to drill all then-remaining net wells on 150 -acre spacing, the investors have the right to require us to repurchase their right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs. We retain the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of the remaining ORRIs once we have drilled a minimum of 1,300 net wells. As of September 30, 2015 , we had drilled 482 net wells. The obligation to deliver future ORRIs has been recorded as a liability which will be settled through the future conveyance of the underlying ORRIs to the investors on a net-well basis, at which time the associated liability will be reversed and the sale of the ORRIs reflected as an adjustment to the capitalized cost of our oil and natural gas properties. Because we did not meet our ORRI commitment in 2012, the ORRI increased to 4% for wells earned in 2013, and the ultimate number of wells in which we must assign an interest will be reduced accordingly. We met our ORRI conveyance commitments as of December 31, 2013 and 2014. In the Prior Quarter and the Prior Period, income of approximately $6 million and $43 million , respectively, was attributable to the noncontrolling interests of CHK Utica. Chesapeake Granite Wash Trust. In November 2011, Chesapeake Granite Wash Trust (the Trust) sold 23,000,000 common units representing beneficial interests in the Trust at a price of $19.00 per common unit in its initial public offering. The common units are listed on the New York Stock Exchange and trade under the symbol “CHKR”. We own 12,062,500 common units and 11,687,500 subordinated units, which in the aggregate represent an approximate 51% beneficial interest in the Trust. The Trust has a total of 46,750,000 units outstanding. In connection with the Trust’s initial public offering, we conveyed royalty interests to the Trust that entitle the Trust to receive (i) 90% of the proceeds (after deducting certain post-production expenses and any applicable taxes) that we receive from the production of hydrocarbons from 69 then-producing wells, and (ii) 50% of the proceeds (after deducting certain post-production expenses and any applicable taxes) in 118 development wells that have been or will be drilled on approximately 45,400 gross acres ( 29,000 net acres) in the Colony Granite Wash play in Washita County in the Anadarko Basin of western Oklahoma. Pursuant to the terms of a development agreement with the Trust, we are obligated to drill and complete, or cause to be drilled and completed, the development wells at our own expense prior to June 30, 2016, and the Trust is not responsible for any costs related to the drilling and completion of the development wells or any other operating or capital costs of the Trust properties. In addition, we granted to the Trust a lien on our remaining interests in the undeveloped properties that are subject to the development agreement in order to secure our drilling obligation to the Trust, although the maximum amount recoverable by the Trust under the lien was limited to $263 million initially and is proportionately reduced as we fulfill our drilling obligation over time. As of September 30, 2015 , we had drilled and completed or caused to be drilled and completed approximately 103 development wells, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $33 million . The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for the quarter. If there is not sufficient cash to fund a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units is reduced or eliminated for the quarter in order to make a distribution, to the extent possible, of up to the subordination threshold amount on the common units. The distribution made with respect to the subordinated units to Chesapeake was either reduced or eliminated for each of the most recent 13 quarters. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for the quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold is to be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through September 30, 2015 , no incentive distributions had been made. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After this time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis. For the Current Period and the Prior Period, the Trust declared and paid the following distributions: Production Period Distribution Date Cash Distribution per Common Unit Cash Distribution per Subordinated Unit March 2015 – May 2015 August 31, 2015 $ 0.3579 $ — December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — March 2014 – May 2014 August 29, 2014 $ 0.5796 $ — December 2013 – February 2014 May 30, 2014 $ 0.6454 $ — September 2013 – November 2013 March 3, 2014 $ 0.6624 $ — We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is consolidated in our condensed consolidated financial statements. As of September 30, 2015 and December 31, 2014 , $264 million and $287 million , respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to the Trust. Net income (loss) attributable to the Trust’s noncontrolling interests is presented in our condensed consolidated statements of operations as income of approximately $1 million in the Current Quarter, income of approximately $6 million in the Prior Quarter, income of a nominal amount in the Current Period and income of approximately $14 million in the Prior Period. See Note 11 for further discussion of VIEs.

Share-Based Compensation (Note)

Share-Based Compensation (Note)	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Compensation Related Costs, Share-based Payments	Share-Based Compensation Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units (PSUs) granted to employees and common stock and restricted stock granted to non-employee directors under our long term incentive plans. The restricted stock and stock options are equity-classified awards and the PSUs are liability-classified awards. Equity-Classified Awards Restricted Stock. We grant restricted stock units to employees and non-employee directors. Prior to 2014, we also granted restricted stock awards as equity compensation. We refer to both types of awards as restricted stock. Restricted stock vests over a minimum of three years and the holder receives dividends, if paid, on unvested shares. A summary of the changes in unvested restricted stock during the Current Period is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2015 10,091 $ 21.20 Granted 7,016 $ 13.97 Vested (4,025 ) $ 21.78 Forfeited (899 ) $ 17.21 Unvested restricted stock as of September 30, 2015 12,183 $ 17.14 The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $59 million based on the stock price at the time of vesting. As of September 30, 2015 , there was approximately $149 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 2.04 years. The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized reductions in tax benefits related to restricted stock of $5 million , $4 million , $11 million and $1 million , respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes. Stock Options. In the Current Period and the Prior Period, we granted members of senior management stock options that vest ratably over a three -year period. In January 2013, we also granted retention awards of stock options to certain officers that vest one-third on each of the third , fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options expire seven to ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 % The following table provides information related to stock option activity for the Current Period: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding at January 1, 2015 4,599 $ 19.55 7.03 $ 5 Granted 1,208 $ 18.37 Exercised (14 ) $ 18.13 $ — Expired (213 ) $ 18.54 Forfeited — $ — Outstanding at September 30, 2015 5,580 $ 19.33 5.83 $ — Exercisable at September 30, 2015 2,248 $ 19.50 4.86 $ — ___________________________________________ (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 September 30, 2015 , there was $10 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.80 years . The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized a reduction in tax benefits related to stock options of nominal amounts. Each adjustment was recorded to additional paid-in capital and deferred income taxes. Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 9 $ 12 $ 33 $ 36 Oil and natural gas properties 3 6 18 22 Oil, natural gas and NGL production expenses 4 5 14 13 Marketing, gathering and compression expenses — 2 3 5 Oilfield services expenses — — — 5 Total $ 16 $ 25 $ 68 $ 81 Liability-Classified Awards Performance Share Units. In 2013, 2014 and 2015, we granted PSUs to senior management that vest ratably over a three -year term and are settled in cash on the third anniversary of the awards. The ultimate amount earned is based on achievement of performance metrics established by the Compensation Committee of the Board of Directors, which include total shareholder return (TSR) and, for certain of the awards, operational performance goals such as finding and development costs and production and proved reserve growth. For PSUs granted in 2013, the TSR component can range from 0% to 125% of base salary, and each of the two operational components can range from 0% to 62.5% ; however, the maximum total payout is capped at 200% . For PSUs granted in 2014, the TSR component can range from 0% to 200% , with no operational components. 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. 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 46.36 % Risk-free interest rate 0.71 % Dividend yield for value of awards — % The following table presents a summary of our 2013, 2014 and 2015 PSU awards: Units Fair Value as of Grant Date Fair Value (a) Liability for Vested Amount (a) ($ in millions) 2013 Awards: Payable 2016 1,701,941 $ 35 $ 9 $ 9 2014 Awards: Payable 2017 609,637 $ 16 $ 1 $ 1 2015 Awards: Payable 2018 696,683 $ 13 $ 4 $ 2 ___________________________________________ (a) As of September 30, 2015 . PSU Compensation. We recognized the following compensation costs (credits) related to PSUs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (2 ) $ (12 ) $ (16 ) $ (2 ) Restructuring and other termination costs (1 ) (17 ) (16 ) (11 ) Marketing, gathering and compression — (1 ) (1 ) — Oil and natural gas properties — — (1 ) 3 Total $ (3 ) $ (30 ) $ (34 ) $ (10 ) Effect of the Spin-off on Share-Based Compensation The employee matters agreement entered into in connection with the June 2014 spin-off of our oilfield services business (see Note 15) addresses the treatment of holders of Chesapeake stock options, restricted stock and PSUs. Unvested equity-based compensation awards held by COO employees were canceled and replaced with new awards of SSE, and unvested equity-based compensation awards held by Chesapeake employees were adjusted to account for the spin-off, each as of the spin-off date. The employee matters agreement provides that employees of SSE ceased to participate in benefit plans sponsored or maintained by Chesapeake as of the spin-off date. In addition, the employee matters agreement provides that as of the spin-off date, each party is responsible for the compensation of its current employees and for all liabilities relating to its former employees, as determined by their respective employer on the date of termination.

Derivative and Hedging Activiti

Derivative and Hedging Activities (Note)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative and Hedging Activities Disclosure	Derivative and Hedging Activities Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on its share of expected production, to reduce its exposure to fluctuations in future commodity prices and to protect its expected operating cash flow against significant market movements or volatility. Chesapeake also uses derivative instruments to mitigate a portion of its exposure to interest rate and foreign currency exchange rate fluctuations. All of our commodity derivative instruments are net settled based on the difference between the fixed-price payment and the floating-price payment, resulting in a net amount due to or from the counterparty. Oil and Natural Gas Derivatives As of September 30, 2015 and December 31, 2014 , our oil and natural gas derivative instruments consisted of the following types of instruments: • Swaps : Chesapeake receives a fixed price and pays a floating market price to the counterparty for the hedged commodity. • Collars: These instruments contain a fixed floor price (put) and ceiling price (call). If the market price exceeds the call strike price or falls below the put strike price, Chesapeake receives the fixed price and pays the market price. If the market price is between the put and the call strike prices, no payments are due from either party. Three-way collars include an additional put option in exchange for a more favorable strike price on the call option. This eliminates the counterparty’s downside exposure below the second put option strike price. • 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 September 30, 2015 and December 31, 2014 are provided below. September 30, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 8.0 $ 161 12.5 $ 471 Three-way collars 1.1 11 4.4 40 Call options 18.1 (9 ) 35.8 (89 ) Basis protection swaps 1.6 — — — Total oil 28.8 $ 163 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 295 $ 174 275 $ 281 Three-way collars 36 28 207 165 Call options 193 (107 ) 193 (170 ) Basis protection swaps 75 (4 ) 60 23 Total natural gas 599 $ 91 735 $ 299 Total estimated fair value $ 254 $ 721 We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss) . Interest Rate Derivatives As of September 30, 2015 , there were no interest rate derivatives outstanding. As of December 31, 2014 , our interest rate derivative instruments consisted of swaps. We enter into fixed-to-floating interest rate swaps (we receive a fixed interest rate and pay a floating market rate) to mitigate our exposure to changes in the fair value of our senior notes. We enter into floating-to-fixed interest rate swaps (we receive a floating market rate and pay a fixed interest rate) to manage our interest rate exposure related to our bank credit facility borrowings. The notional amount of our interest rate derivatives associated with our long-term debt as of December 31, 2014 was $850 million . The estimated fair value of our interest rate derivative liabilities as of December 31, 2014 was $17 million . We have terminated certain fair value hedges related to certain of our senior notes. Gains and losses related to these terminated hedges will be amortized as an adjustment to interest expense over the remaining term of the related senior notes. Over the next six years , we will recognize $8 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 that may result from the €344 million principal amount of our euro-denominated senior notes. 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. Under the terms of the cross currency swaps we currently hold, on each semi-annual interest payment date, the counterparties pay us €11 million and we pay the counterparties $17 million , which yields an annual dollar-equivalent interest rate of 7.491% . Upon maturity of the notes, the counterparties will pay us €344 million and we will pay the counterparties $459 million . 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 $76 million and $53 million as of September 30, 2015 and December 31, 2014 , respectively. The euro-denominated debt in long-term debt has been adjusted to $384 million as of September 30, 2015 , using an exchange rate of $1.1177 to €1.00. Supply Contract Derivatives From time to time and in the normal course of business, our marketing subsidiary enters into supply contracts under which we commit to deliver a predetermined quantity of natural gas to certain counterparties in an attempt to earn attractive margins. Under certain contracts, we receive a sales price that is based on the price of a product other than natural gas, thereby creating an embedded derivative requiring bifurcation. In one of these supply contracts, we are committed to supply a minimum of 90 bbtu per day of natural gas through March 2025. In the Current Quarter and the Current Period, we recorded revenues of approximately $36 million and $63 million , respectively, for settlements of this embedded derivative. The bifurcated derivative was measured at fair value as of September 30, 2015 , which resulted in unrealized gains of $70 million and $291 million in the Current Quarter and Current Period, respectively. Both settlements and mark-to-market gains (losses) are included in marketing, gathering and compression revenues in our condensed consolidated statements of operations. Effect of Derivative Instruments – Condensed Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet ($ in millions) As of September 30, 2015 Commodity Contracts: Short-term derivative asset $ 370 $ (71 ) $ 299 Long-term derivative asset 12 (3 ) 9 Short-term derivative liability (95 ) 71 (24 ) Long-term derivative liability (33 ) 3 (30 ) Total commodity contracts 254 — 254 Foreign Currency Contracts: (a) Long-term derivative liability (76 ) — (76 ) Total foreign currency contracts (76 ) — (76 ) Supply Contracts: Short-term derivative asset 43 — 43 Long-term derivative asset 248 — 248 Total supply contracts 291 — 291 Total derivatives $ 469 $ — $ 469 Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet As of December 31, 2014 Commodity Contracts: Short-term derivative asset $ 974 $ (95 ) $ 879 Long-term derivative asset 16 (10 ) 6 Short-term derivative liability (105 ) 95 (10 ) Long-term derivative liability (163 ) 10 (153 ) Total commodity contracts 722 — 722 Interest Rate Contracts: Short-term derivative liability (5 ) — (5 ) Long-term derivative liability (12 ) — (12 ) Total interest rate contracts (17 ) — (17 ) Foreign Currency Contracts: (a) Long-term derivative liability (53 ) — (53 ) Total foreign currency contracts (53 ) — (53 ) Total derivatives $ 652 $ — $ 652 ____________________________________________ (a) Designated as cash flow hedging instruments. As of September 30, 2015 and December 31, 2014 , 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, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL revenues $ 653 $ 1,777 $ 2,353 $ 5,842 Gains (losses) on undesignated oil and natural gas derivatives 234 569 369 (5 ) Losses on terminated cash flow hedges (7 ) (5 ) (29 ) (25 ) Total oil, natural gas and NGL revenues $ 880 $ 2,341 $ 2,693 $ 5,812 The components of marketing, gathering and compression revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression revenues (a) $ 1,943 $ 3,362 $ 5,703 $ 9,543 Gains on undesignated supply contract derivatives 70 — 290 — Total marketing, gathering and compression revenues $ 2,013 $ 3,362 $ 5,993 $ 9,543 ____________________________________________ (a) Current Quarter and Current Period settlements of $41 million and $77 million , respectively, on supply contracts accounted for as derivatives are included in marketing, gathering and compression revenues. The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Interest expense on senior notes $ 171 $ 170 $ 513 $ 534 Interest expense on term loan — — — 36 Amortization of loan discount, issuance costs and other 14 9 37 44 Interest expense on credit facilities 2 6 8 22 Gains on terminated fair value hedges — — (2 ) (2 ) (Gains) losses on undesignated interest rate derivatives — 2 (10 ) (48 ) Capitalized interest (99 ) (170 ) (336 ) (504 ) Total interest expense $ 88 $ 17 $ 210 $ 82 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 September 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (211 ) $ (131 ) $ (243 ) $ (154 ) Net change in fair value 12 7 — — Losses reclassified to income 7 5 5 3 Balance, end of period $ (192 ) $ (119 ) $ (238 ) $ (151 ) Nine Months Ended September 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (231 ) $ (143 ) $ (269 ) $ (167 ) Net change in fair value 10 6 6 3 Losses reclassified to income 29 18 25 13 Balance, end of period $ (192 ) $ (119 ) $ (238 ) $ (151 ) Approximately $118 million of the $119 million of accumulated other comprehensive loss as of September 30, 2015 represented the net deferred loss associated with commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. Deferred gain or loss amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of September 30, 2015 , we expect to transfer approximately $20 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 September 30, 2015 , our oil, natural gas, interest rate and supply contract derivative instruments were spread among 17 counterparties. Hedging Arrangements As of September 30, 2015 , our secured commodity hedging facility with nine counterparties provided approximately 444 mmboe of hedging capacity for oil, natural gas and NGL price derivatives and 444 mmboe for basis derivatives with an aggregate mark-to-market capacity of $7.1 billion . The facility is secured by proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility by at least 1.65 times at semi-annual collateral redetermination dates and 1.30 times in between those dates, and guarantees by certain subsidiaries that also guarantee our revolving credit facility and indentures. We have significant flexibility with regard to releases and/or substitutions of pledged reserves, provided that certain requirements are met including maintaining specified collateral coverage ratios as well as maintaining credit ratings with either of the designated rating agencies at or above current levels. The counterparties’ obligations under the facility must be secured by cash or short-term U.S. treasury instruments to the extent that any mark-to-market amounts owed to us exceed defined thresholds. As of September 30, 2015 , we had hedged under the facility 27.3 mmboe of our future production with price derivatives and 1.2 mmboe with basis derivatives. In April 2015, we also began entering into bilateral hedging agreements with the intention of replacing and terminating the respective counterparties’ positions in the secured hedging facility. In the Current Period, we entered into bilateral arrangements that reduced the aggregate mark-to-market capacity under the secured hedging facility from $16.5 billion to $7.1 billion . The counterparties’ and our obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts owed to us or by us exceed defined thresholds. As of September 30, 2015 , we had hedged under bilateral agreements 87.2 mmboe of our future production with price derivatives and 12.9 mmboe with basis derivatives. Fair Value The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 343 $ 39 $ 382 Commodity liabilities — (12 ) (116 ) (128 ) Interest rate liabilities — — — — Foreign currency liabilities — (76 ) — (76 ) Supply contract assets — — 291 291 Total derivatives $ — $ 255 $ 214 $ 469 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 99 281 Total purchases, issuances, sales and settlements: Settlements (122 ) 9 Ending balance as of September 30, 2015 $ (77 ) $ 291 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 53 — Total purchases, issuances, sales and settlements: Settlements 124 — Transfers (b) (4 ) — Ending balance as of September 30, 2014 $ (305 ) $ — ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 99 $ 53 $ 281 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 72 $ 60 $ 281 $ — (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 September 30, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value September 30, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 23.69% – 37.51% 31.70% $ 2 Supply contracts (b) Oil price volatility curves 20.22% – 44.86% 23.82% $ 291 Natural gas trades (a) Natural gas price volatility curves 19.76% – 61.06% 31.31% $ (79 ) ___________________________________________ (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)	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
Mergers, Acquisitions and Dispositions Disclosure	Oil and Natural Gas Property Transactions In the Current Quarter, CHK C-T sold all of its oil and natural gas properties to FourPoint and immediately used the consideration, plus other cash it had on hand, to repurchase and cancel all of CHK C-T’s outstanding preferred shares. In a related transaction, we sold noncore properties adjacent to the CHK C-T properties to FourPoint for approximately $90 million . In the Prior Quarter, we exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI was the designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we were the designated operator. In conjunction with the exchange, we paid RKI approximately $450 million in cash. During the Prior Quarter, we sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE), for net proceeds of $233 million . During the Prior Quarter, we sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million . Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below. During the Current Period and the Prior Period, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds related to divestitures of other noncore oil and natural gas properties of approximately $52 million and $335 million , respectively. Under full cost accounting rules, we accounted for the sales of oil and natural gas properties discussed above as adjustments to capitalized costs, with no recognition of gain or loss as the sales have not involved a significant change in proved reserves or significantly altered the relationship between costs and proved reserves. Joint Ventures Between July 2008 and June 2013, we entered into eight significant joint ventures with other leading energy companies, including Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (Total), CNOOC Limited, Statoil, BP America and Freeport-McMoRan Inc. (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion . In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of September 30, 2015 , we had utilized all drilling carries from our joint venture partners. During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $51 million and $535 million , respectively, in drilling and completion carries paid by our joint venture partners. During the Current Period and the Prior Period, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford shales and Mid-Continent plays to our joint venture partners for approximately $30 million and $24 million , respectively. Volumetric Production Payments From time to time, we have sold certain of our producing assets located in more mature producing regions through the sale of VPPs. A VPP is a limited-term overriding royalty interest in oil and natural gas reserves that (i) entitles the purchaser to receive scheduled production volumes over a period of time from specific lease interests; (ii) is free and clear of all associated future production costs and capital expenditures; (iii) is nonrecourse to the seller (i.e., the purchaser’s only recourse is to the reserves acquired); (iv) transfers title of the reserves to the purchaser; and (v) allows the seller to retain all production beyond the specified volumes, if any, after the scheduled production volumes have been delivered. For all of our VPP transactions, we novated to each of the respective VPP buyers hedges that covered all VPP volumes sold. If contractually scheduled volumes exceed the actual volumes produced from the VPP wellbores that are attributable to the ORRI conveyed, either the shortfall will be made up from future production from these wellbores (or, at our option, from our retained interest in the wellbores) through an adjustment mechanism, or the initial term of the VPP will be extended until all scheduled volumes, to the extent produced, are delivered from the VPP wellbores to the VPP buyer. We retain drilling rights on the properties below currently producing intervals and outside of producing wellbores. As the operator of the properties from which the VPP volumes have been sold, we bear the cost of producing the reserves attributable to these interests, which we include as a component of production expenses and production taxes in our 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 September 30, 2015 , our outstanding VPPs consisted of the following: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 10 March 2012 Anadarko Basin Granite Wash $ 744 3.0 87 9.2 160 9 May 2011 Mid-Continent 853 1.7 138 4.8 177 4 December 2008 Anadarko and Arkoma Basins 412 0.5 95 — 98 3 August 2008 Anadarko Basin 600 — 93 — 93 2 May 2008 Texas, Oklahoma and Kansas 622 — 94 — 94 1 December 2007 Kentucky and West Virginia 1,100 — 208 — 208 $ 4,331 5.2 715 14.0 830 The volumes produced on behalf of our VPP buyers during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 76.0 2.1 253.3 4.0 98.0 2.6 314.5 5.0 9 41.4 3.6 92.9 4.3 46.1 3.8 101.5 4.7 8 (a) — 8.9 — 8.9 — 14.8 — 14.8 6 (b) — — — — 6.0 1.1 — 1.1 5 (b) — — — — 4.2 1.2 — 1.2 4 10.5 2.0 — 2.0 11.9 2.2 — 2.3 3 — 1.6 — 1.6 — 1.8 — 1.8 2 — 1.0 — 1.0 — 1.1 — 1.1 1 — 3.2 — 3.2 — 3.4 — 3.4 127.9 22.4 346.2 25.0 166.2 32.0 416.0 35.4 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 237.0 6.5 798.3 12.7 310.0 8.1 989.6 15.8 9 127.5 10.8 284.8 13.2 142.6 11.7 311.9 14.4 8 (a) — 36.5 — 36.5 — 45.7 — 45.7 6 (b) — — — — 18.0 3.3 — 3.4 5 (b) — — — — 16.5 4.6 — 4.7 4 32.2 6.1 — 6.2 36.5 6.8 — 7.0 3 — 4.9 — 4.9 — 5.5 — 5.5 2 — 3.1 — 3.1 — 5.1 — 5.1 1 — 10.0 — 10.0 — 10.4 — 10.4 396.7 77.9 1,083.1 86.6 523.6 101.2 1,301.5 112.0 ____________________________________________ (a) VPP #8 expired in August 2015. (b) In 2014, we divested the properties associated with VPP #5 and VPP #6. The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2015 were as follows: Volume Remaining as of September 30, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 77 1.1 31.5 3.9 61.3 9 65 0.7 62.5 1.7 76.6 4 15 — 9.3 — 9.6 3 46 — 19.1 — 19.1 2 43 — 10.8 — 10.8 1 87 — 81.6 — 81.6 1.8 214.8 5.6 259.0

Investments (Note)

Investments (Note)	9 Months Ended
	Sep. 30, 2015
Investments [Abstract]
Investments Disclosure	Investments A summary of our investments, including our approximate ownership percentage and carrying value as of September 30, 2015 and December 31, 2014 , is presented below. Approximate Ownership % Carrying Value Accounting Method September 30, December 31, September 30, December 31, ($ in millions) FTS International, Inc. Equity 30% 30% $ 88 $ 116 Sundrop Fuels, Inc. Equity 56% 56% 119 130 Other — —% —% 18 19 Total investments $ 225 $ 265 FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is a privately held company that, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. During the Current Period, we recorded negative equity method and other adjustments, prior to intercompany profit eliminations, of $72 million for our share of FTS’ net loss and an accretion adjustment of $44 million related to the excess of our underlying equity in net assets of FTS over our carrying value. Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), based in Longmont, Colorado, is a privately held cellulosic biofuels company that is constructing a nonfood biomass-based “green gasoline” plant. During the Current Period, we recorded an $18 million charge related to our share of Sundrop's net loss and $7 million of capitalized interest associated with the construction of Sundrop’s plant. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $85 million as of September 30, 2015 and will be amortized over the life of the plant once it is placed into service. Sold Investments Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties. In the Prior Period, we sold all of our interest in Chaparral for net cash proceeds of $209 million . We recorded a $73 million gain related to the sale. Other. In the Prior Period, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

Variable Interest Entities (Not

Variable Interest Entities (Note)	9 Months Ended
	Sep. 30, 2015
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Variable Interest Entities Disclosure	Variable Interest Entities We consolidate the activities of VIEs for which we are the primary beneficiary. In order to determine whether we own a variable interest in a VIE, we perform a qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements. Consolidated VIE Chesapeake Granite Wash Trust . For a discussion of the formation, operations and presentation of the Trust, see Noncontrolling Interests in Note 6. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that potentially could be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest. The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of September 30, 2015 , $1 million of cash and cash equivalents, $488 million of proved oil and natural gas properties, $397 million of accumulated depreciation, depletion and amortization and $11 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 is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million , and the partnership will acquire the remaining 90% up to a maximum of $225 million , funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5% . The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment. The carrying value of our investment was $10 million as of September 30, 2015 .

Other Property and Equipment (N

Other Property and Equipment (Note)	9 Months Ended
	Sep. 30, 2015
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]
Other Property and Equipment Disclosure	Other Property and Equipment Net (Gains) Losses on Sales of Fixed Assets A summary by asset class of (gains) or losses on sales of fixed assets for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Natural gas compressors $ (1 ) $ (75 ) $ (1 ) $ (195 ) Gathering systems and treating plants 1 (5 ) 1 8 Oilfield services equipment — — — (7 ) Buildings and land (1 ) (6 ) — (5 ) Other — — 3 (2 ) Total net (gains) losses on sales of fixed assets $ (1 ) $ (86 ) $ 3 $ (201 ) In the Prior Quarter, as part of a divestiture of noncore oil and natural gas properties in South Texas, we sold 61 compressors and related equipment to Hilcorp Energy Company for $19 million and recorded a $6 million gain on the sale. In the Prior Period, we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million , which included the sale of 162 compressors and related equipment for approximately $133 million in the Prior Quarter. We recorded a $161 million gain associated with the transactions, which included a $68 million gain in the Prior Quarter. In the Prior Period, we also sold 102 compressors and related equipment to Access Midstream Partners, L.P. (ACMP) for proceeds of approximately $159 million . We recorded a $24 million gain associated with the transaction. Assets Held for Sale We are continuing to pursue the sale of buildings and land located primarily in Oklahoma, West Virginia and the Fort Worth, Texas area. Buildings and land are recorded within our other segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of September 30, 2015 . Oil and natural gas properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. As of September 30, 2015 and December 31, 2014 , we had $94 million and $93 million , respectively, of buildings and land, net of accumulated depreciation, classified as assets held for sale on our condensed consolidated balance sheets.

Impairments (Note)

Impairments (Note)	9 Months Ended
	Sep. 30, 2015
Asset Impairment Charges [Abstract]
Asset Impairment Charges Disclosure	Impairments Impairments of Oil and Natural Gas Properties On a quarterly basis, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with proved reserves, leasehold that expired in the quarter and leasehold that is no longer part of our development strategy and will be abandoned. As commodity prices have decreased significantly over the past 12 months, we transferred, in the Current Quarter, unproved leasehold having a cost of approximately $1.0 billion that would not be a part of our development strategy going forward. The acreage is noncore and is spread out across most of our operating areas. 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 Current Period, 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 $5.416 billion and $15.407 billion , respectively. Cash flow hedges as of September 30, 2015 , which related to future periods, increased the ceiling test impairment by $184 million . Based on the first-day-of the-month prices we have received over the 11 months ended November 1, 2015, we expect to record another material write-down in the carrying value of our oil and natural gas properties in the fourth quarter of 2015. 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 Compressors. In the Current Period, we recorded a $21 million impairment related to 466 compressors that were sold in the Current Quarter for the difference between the aggregate sales price of $63 million and the carrying value. Contract Termination Charges . In the Current Period, as a result of reductions in our planned drilling activity in response to declines in oil and natural gas prices, we terminated contracts with drilling contractors and incurred charges of $7 million . Further contract termination charges in subsequent quarters may occur if commodity prices remain low or continue to decline. The contract termination charges are included in our exploration and production operating segment. Oilfield Services Equipment. In the Prior Period, we purchased 31 leased rigs and equipment from various lessors for an aggregate purchase price of $140 million . In connection with these purchases, we paid $8 million in early lease termination costs, which are included in impairments of fixed assets and other in the condensed consolidated statement of operations. In addition, we recognized an impairment loss of approximately $15 million related to leasehold improvements associated with these assets. The drilling rigs and equipment are included in our former oilfield services operating segment. Other. In the Current Period, we recorded a $47 million loss contingency related to contract disputes. In the Current Quarter and the Current Period, we recorded a $9 million and $22 million impairment of a note receivable as a result of the increased credit risk associated with declining commodity prices. In addition, under the terms of our joint venture agreements (see Note 9), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In the Current Quarter, we entered into a settlement with Total regarding our acreage maintenance commitment in our Barnett Shale joint venture and accrued a $70 million charge. In the Prior Period, we revised our estimate of our net acreage shortfall with Total under the terms of our Barnett Shale joint venture agreement and recorded a $22 million charge. See Note 4 for additional discussion regarding our net acreage maintenance commitments. Nonrecurring Fair Value Measurements. Fair value measurements for certain of the impairments discussed above were based on recent sales information for comparable assets. As the fair value was estimated using the market approach based on recent prices from orderly sales transactions for comparable assets between market participants, these values were classified as Level 2 in the fair value hierarchy. Other inputs used were not observable in the market; these values were classified as Level 3 in the fair value hierarchy.

Restructuring (Note)

Restructuring (Note)	9 Months Ended
	Sep. 30, 2015
Restructuring and Related Activities [Abstract]
Restructuring and Related Activities Disclosure [Text Block]	14. Restructuring and Other Termination Costs Workforce Reduction On September 29, 2015, we reduced our workforce by approximately 15% as part of an overall plan to reduce costs and better align our workforce with the needs of our business and current oil and natural gas commodity prices. In connection with the reduction, we incurred a total charge of approximately $55 million in the Current Quarter for one-time termination benefits, all of which will be paid in cash in the 2015 fourth quarter. Other We recognized a credit of $16 million in the Current Period related to negative fair value adjustments to PSUs granted to former executives of the Company which corresponded to a decrease in the trading price of our common stock. The Prior Period amount included $15 million of charges incurred in connection with the spin-off of our oilfield services business and senior management separations.

Spin-Off of Oilfield Services B

Spin-Off of Oilfield Services Business Spin-Off of Oilfield Services Business (Note)	9 Months Ended
	Sep. 30, 2015
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations, Disclosure	Spin-Off of Oilfield Services Business On June 30, 2014, we completed the spin-off of our oilfield services business, which we previously conducted through our indirect, wholly owned subsidiary COO, into SSE, an independent, publicly traded company. Following the close of business on June 30, 2014, we distributed to Chesapeake shareholders one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock held on June 19, 2014, the record date for the distribution. Prior to the completion of the spin-off, we and COO and its affiliates engaged in the following series of transactions: • COO and certain of its subsidiaries entered into a $275 million senior secured revolving credit facility and a $400 million secured term loan, the proceeds of which were used to repay in full and terminate COO’s then-existing credit facility. • COO distributed to us its compression unit manufacturing business, its geosteering business and the proceeds from the sale of substantially all of its crude oil hauling business. See Note 12 for further discussion of the sale. • We transferred to a subsidiary of COO, at carrying value, certain of our buildings and land, most of which COO had been leasing from us prior to the spin-off. • COO issued $500 million of 6.5% Senior Notes due 2022 in a private placement and used the net proceeds to make a cash distribution of approximately $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility and for general corporate purposes. • COO converted from a limited liability company into Seventy Seven Energy Inc., a publicly-traded corporation. • We distributed all of SSE’s outstanding shares to our shareholders, which resulted in SSE becoming an independent, publicly traded company. Following the spin-off, we have no ownership interest in SSE. Therefore, we ceased to consolidate SSE’s assets and liabilities as of the spin-off date. Because we expect to have significant continued involvement associated with SSE’s future operations through the various agreements we entered into in connection with the spin-off, our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations. For segment disclosures, we have labeled our oilfield services segment as “Former Oilfield Services”. See Note 18 for additional information regarding our segments. In the Prior Period, our stockholders’ equity decreased by $270 million , net of $152 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our consolidated statement of operations.

Income Taxes

Income Taxes	9 Months Ended
	Sep. 30, 2015
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 such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry. Based on the material write-downs of the carrying value of our oil and natural gas properties and our expected operating results in the 2015 fourth quarter, we project being in a net deferred tax asset position at December 31, 2015. 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, 2015. Such objective negative evidence limits the ability to consider other subjective positive evidence, such as our projections for future growth. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as future expected growth.

Fair Value Measurements (Note)

Fair Value Measurements (Note)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements Disclosure	Fair Value Measurements Recurring Fair Value Measurements Other Current Assets. Assets related to Chesapeake’s deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange-traded securities. Other Current Liabilities . Liabilities related to Chesapeake’s deferred compensation plan are included in other current liabilities. The fair values of these liabilities are determined using quoted market prices as the plan consists of exchange-traded mutual funds. Financial Assets (Liabilities) . The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Financial Assets (Liabilities): Other current assets $ 58 $ — $ — $ 58 Other current liabilities (60 ) — — (60 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 ) See Note 3 for information regarding fair value measurement of our debt instruments. See Note 8 for information regarding fair value measurement of our derivatives. Nonrecurring Fair Value Measurements See Note 13 regarding nonrecurring fair value measurements.

Segment Information (Note)

Segment Information (Note)	9 Months Ended
	Sep. 30, 2015
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Segment Information Disclosure	Segment Information As of September 30, 2015 , we have two reportable operating segments, each of which is managed separately because of the nature of its operations. The exploration and production operating segment is responsible for finding and producing oil, natural gas and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of oil, natural gas and NGL. In addition, prior to the spin-off of our oilfield services business in June 2014, our former oilfield services operating segment was responsible for drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties. Our former oilfield services segment’s historical financial results for periods prior to the spin-off continue to be included in our historical financial results as a component of continuing operations, as reflected in the table below. Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of oil, natural gas and NGL related to Chesapeake’s ownership interests by our marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. These amounts totaled $1.046 billion , $2.150 billion , $3.483 billion and $6.746 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively. Revenues generated by our former oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment were reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $544 million for the Prior Period. No income was recognized in our condensed consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Three Months Ended September 30, 2015 Revenues $ 853 $ 3,059 $ — $ — $ (1,019 ) $ 2,893 Intersegment revenues 27 (1,046 ) — — 1,019 — Total revenues $ 880 $ 2,013 $ — $ — $ — $ 2,893 Income (Loss) Before Income Taxes $ (5,625 ) $ 70 $ — $ (37 ) $ 16 $ (5,576 ) Three Months Ended September 30, 2014 Revenues $ 2,341 $ 5,512 $ — $ — $ (2,150 ) $ 5,703 Intersegment revenues — (2,150 ) — — 2,150 — Total revenues $ 2,341 $ 3,362 $ — $ — $ — $ 5,703 Income (Loss) Before Income Taxes $ 987 $ 113 $ — $ (63 ) $ 92 $ 1,129 Nine Months Ended September 30, 2015 Revenues $ 2,614 $ 9,476 $ — $ — $ (3,404 ) $ 8,686 Intersegment revenues 79 (3,483 ) — — 3,404 — Total revenues $ 2,693 $ 5,993 $ — $ — $ — $ 8,686 Income (Loss) Before Income Taxes $ (16,759 ) $ 208 $ — $ (82 ) $ 369 $ (16,264 ) Nine Months Ended September 30, 2014 Revenues $ 5,812 $ 16,289 $ 1,060 $ 30 $ (7,290 ) $ 15,901 Intersegment revenues — (6,746 ) (544 ) — 7,290 — Total revenues $ 5,812 $ 9,543 $ 516 $ 30 $ — $ 15,901 Income (Loss) Before Income Taxes $ 2,089 $ 325 $ (16 ) $ (24 ) $ (128 ) $ 2,246 As of September 30, 2015 Total Assets $ 15,646 $ 1,711 $ — $ 4,342 $ (413 ) $ 21,286 As of December 31, 2014 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Note)	9 Months Ended
	Sep. 30, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Condensed Financial Information of Parent Company Only Disclosure	Condensed Consolidating Financial Information Chesapeake Energy Corporation is a holding company, owns no operating assets and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors. Our former oilfield services subsidiaries were separately capitalized and were not guarantors of our debt obligations. The tables below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2015 and December 31, 2014 and for the three and nine months ended September 30, 2015 and 2014. This financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities. CONDENSED CONSOLIDATING BALANCE SHEET AS OF SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 1,849 $ 12 $ 1 $ (103 ) $ 1,759 Restricted cash — — — — — Other 69 1,736 15 — 1,820 Intercompany receivable, net 24,909 — 457 (25,366 ) — Total Current Assets 26,827 1,748 473 (25,469 ) 3,579 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 13,503 98 1,125 14,726 Other property and equipment, net — 2,139 — — 2,139 Property and equipment held for sale, net — 94 — — 94 Total Property and Equipment, Net — 15,736 98 1,125 16,959 LONG-TERM ASSETS: Other assets 112 626 10 — 748 Investments in subsidiaries and intercompany advances (10,358 ) 788 — 9,570 — TOTAL ASSETS $ 16,581 $ 18,898 $ 581 $ (14,774 ) $ 21,286 CURRENT LIABILITIES: Current liabilities $ 1,529 $ 3,118 $ 13 $ (103 ) $ 4,557 Intercompany payable, net — 24,788 — (24,788 ) — Total Current Liabilities 1,529 27,906 13 (24,891 ) 4,557 LONG-TERM LIABILITIES: Long-term debt, net 10,674 — — — 10,674 Deferred income tax liabilities (5 ) 516 32 31 574 Other long-term liabilities 101 834 — — 935 Total Long-Term Liabilities 10,770 1,350 32 31 12,183 EQUITY: Chesapeake stockholders’ equity 4,282 (10,358 ) 536 9,822 4,282 Noncontrolling interests — — — 264 264 Total Equity 4,282 (10,358 ) 536 10,086 4,546 TOTAL LIABILITIES AND EQUITY $ 16,581 $ 18,898 $ 581 $ (14,774 ) $ 21,286 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 Restricted cash — — 38 — 38 Other 55 3,174 93 — 3,322 Intercompany receivable, net 24,527 — 341 (24,868 ) — Total Current Assets 28,682 3,176 556 (24,946 ) 7,468 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 28,358 1,112 673 30,143 Other property and equipment, net — 2,276 3 — 2,279 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 30,727 1,115 673 32,515 LONG-TERM ASSETS: Other assets 153 618 26 (29 ) 768 Investments in subsidiaries and intercompany advances 126 467 — (593 ) — TOTAL ASSETS $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CURRENT LIABILITIES: Current liabilities $ 792 $ 5,081 $ 68 $ (78 ) $ 5,863 Intercompany payable, net — 24,940 — (24,940 ) — Total Current Liabilities 792 30,021 68 (25,018 ) 5,863 LONG-TERM LIABILITIES: Long-term debt, net 11,154 — — — 11,154 Deferred income tax liabilities — 3,751 234 200 4,185 Other long-term liabilities 112 1,090 142 — 1,344 Total Long-Term Liabilities 11,266 4,841 376 200 16,683 EQUITY: Chesapeake stockholders’ equity 16,903 126 1,253 (1,379 ) 16,903 Noncontrolling interests — — — 1,302 1,302 Total Equity 16,903 126 1,253 (77 ) 18,205 TOTAL LIABILITIES AND EQUITY $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 855 $ 25 $ — $ 880 Marketing, gathering and compression — 2,013 — — 2,013 Total Revenues — 2,868 25 — 2,893 OPERATING EXPENSES: Oil, natural gas and NGL production — 245 6 — 251 Production taxes — 25 — — 25 Marketing, gathering and compression — 1,955 — — 1,955 General and administrative 1 47 1 — 49 Restructuring and other termination costs — 53 — — 53 Oil, natural gas and NGL depreciation, depletion and amortization — 478 11 (1 ) 488 Depreciation and amortization of other assets — 31 — — 31 Impairment of oil and natural gas properties — 5,412 37 (33 ) 5,416 Impairments of fixed assets and other — 79 — — 79 Net gains on sales of fixed assets — (1 ) — — (1 ) Total Operating Expenses 1 8,324 55 (34 ) 8,346 LOSS FROM OPERATIONS (1 ) (5,456 ) (30 ) 34 (5,453 ) OTHER INCOME (EXPENSE): Interest expense (182 ) (58 ) — 152 (88 ) Losses on investments — (33 ) — — (33 ) Other income (expense) 140 (113 ) — (29 ) (2 ) Equity in net earnings (losses) of subsidiary (4,594 ) (50 ) — 4,644 — Total Other Expense (4,636 ) (254 ) — 4,767 (123 ) LOSS BEFORE INCOME TAXES (4,637 ) (5,710 ) (30 ) 4,801 (5,576 ) INCOME TAX BENEFIT (EXPENSE) 15 (985 ) 7 26 (937 ) NET LOSS (4,652 ) (4,725 ) (37 ) 4,775 (4,639 ) Net income attributable to noncontrolling interests — — — (13 ) (13 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (4,652 ) (4,725 ) (37 ) 4,762 (4,652 ) Other comprehensive income 8 4 — — 12 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (4,644 ) $ (4,721 ) $ (37 ) $ 4,762 $ (4,640 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 2,223 $ 118 $ — $ 2,341 Marketing, gathering and compression — 3,361 1 — 3,362 Total Revenues — 5,584 119 — 5,703 OPERATING EXPENSES: Oil, natural gas and NGL production — 289 9 — 298 Production taxes — 61 1 — 62 Marketing, gathering and compression — 3,368 1 — 3,369 General and administrative — 59 1 — 60 Restructuring and other termination costs — (14 ) — — (14 ) Provision for legal contingencies — 100 — — 100 Oil, natural gas and NGL depreciation, depletion and amortization — 662 44 (18 ) 688 Depreciation and amortization of other assets — 37 — — 37 Impairment of oil and natural gas — — 104 (104 ) — Impairments of fixed assets and other — 15 — — 15 Net gains on sales of fixed assets — (86 ) — — (86 ) Total Operating Expenses — 4,491 160 (122 ) 4,529 INCOME (LOSS) FROM OPERATIONS — 1,093 (41 ) 122 1,174 OTHER INCOME (EXPENSE): Interest expense (178 ) (11 ) — 172 (17 ) Losses on investments — (27 ) — — (27 ) Other income 56 119 (4 ) (172 ) (1 ) Equity in net earnings (losses) of subsidiary 737 (58 ) — (679 ) — Total Other Income (Expense) 615 23 (4 ) (679 ) (45 ) INCOME BEFORE INCOME TAXES 615 1,116 (45 ) (557 ) 1,129 INCOME TAX EXPENSE (BENEFIT) (47 ) 454 (17 ) 47 437 NET INCOME (LOSS) 662 662 (28 ) (604 ) 692 Net income attributable to noncontrolling interests — — — (30 ) (30 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 662 662 (28 ) (634 ) 662 Other comprehensive income (loss) — 3 — — 3 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 662 $ 665 $ (28 ) $ (634 ) $ 665 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 2,583 $ 110 $ — $ 2,693 Marketing, gathering and compression — 5,993 — — 5,993 Total Revenues — 8,576 110 — 8,686 OPERATING EXPENSES: Oil, natural gas and NGL production — 799 27 — 826 Production taxes — 85 2 — 87 Marketing, gathering and compression — 5,750 1 — 5,751 General and administrative 3 168 3 — 174 Restructuring and other termination costs — 39 — — 39 Provision for legal contingencies 339 20 — — 359 Oil, natural gas and NGL depreciation, depletion and amortization — 1,727 66 (20 ) 1,773 Depreciation and amortization of other assets — 100 — — 100 Impairment of oil and natural gas properties — 15,395 443 (431 ) 15,407 Impairments of fixed assets and other — 167 — — 167 Net losses on sales of fixed assets — 3 — — 3 Total Operating Expenses 342 24,253 542 (451 ) 24,686 LOSS FROM OPERATIONS (342 ) (15,677 ) (432 ) 451 (16,000 ) OTHER INCOME (EXPENSE): Interest expense (532 ) (133 ) — 455 (210 ) Losses on investments — (57 ) — — (57 ) Other income 100 5 — (102 ) 3 Equity in net earnings (losses) of subsidiary (11,908 ) (381 ) — 12,289 — Total Other Expense (12,340 ) (566 ) — 12,642 (264 ) LOSS BEFORE INCOME TAXES (12,682 ) (16,243 ) (432 ) 13,093 (16,264 ) INCOME TAX BENEFIT (182 ) (3,720 ) (101 ) 189 (3,814 ) NET LOSS (12,500 ) (12,523 ) (331 ) 12,904 (12,450 ) Net income attributable to noncontrolling interests — — — (50 ) (50 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (12,500 ) (12,523 ) (331 ) 12,854 (12,500 ) Other comprehensive income (loss) 6 18 — — 24 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (12,494 ) $ (12,505 ) $ (331 ) $ 12,854 $ (12,476 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 5,505 $ 310 $ (3 ) $ 5,812 Marketing, gathering and compression — 9,539 4 — 9,543 Oilfield services — 41 983 (478 ) 546 Total Revenues — 15,085 1,297 (481 ) 15,901 OPERATING EXPENSES: Oil, natural gas and NGL production — 837 31 — 868 Production taxes — 181 4 — 185 Marketing, gathering and compression — 9,512 3 — 9,515 Oilfield services — 53 769 (391 ) 431 General and administrative — 182 47 — 229 Restructuring and other termination costs — 9 3 — 12 Provision for legal contingencies — 100 — — 100 Oil, natural gas and NGL depreciation, depletion and amortization — 1,910 124 (57 ) 1,977 Depreciation and amortization of other assets — 116 142 (64 ) 194 Impairment of oil and natural gas — — 202 (202 ) — Impairments of fixed assets and other — 52 23 — 75 Net gains on sales of fixed assets — (194 ) (7 ) — (201 ) Total Operating Expenses — 12,758 1,341 (714 ) 13,385 INCOME (LOSS) FROM OPERATIONS — 2,327 (44 ) 233 2,516 OTHER INCOME (EXPENSE): Interest expense (524 ) (14 ) (42 ) 498 (82 ) Losses on investments — (69 ) (5 ) 2 (72 ) Net gain on sales of investments — 67 — — 67 Losses on purchases of debt (195 ) — — — (195 ) Other income (expense) 535 3 (2 ) (524 ) 12 Equity in net earnings (losses) of subsidiary 1,391 (167 ) — (1,224 ) — Total Other Income (Expense) 1,207 (180 ) (49 ) (1,248 ) (270 ) INCOME (LOSS) BEFORE INCOME TAXES 1,207 2,147 (93 ) (1,015 ) 2,246 INCOME TAX EXPENSE (BENEFIT) (70 ) 884 (36 ) 81 859 NET INCOME (LOSS) 1,277 1,263 (57 ) (1,096 ) 1,387 Net income attributable to noncontrolling interests — — — (110 ) (110 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 1,277 1,263 (57 ) (1,206 ) 1,277 Other comprehensive income 3 8 — — 11 COMPREHENSIVE INCOME (LOSS) $ 1,280 $ 1,271 $ (57 ) $ (1,206 ) $ 1,288 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 950 $ 105 $ — $ 1,055 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,633 ) (63 ) — (2,696 ) Acquisitions of proved and unproved properties — (407 ) — — (407 ) Proceeds from divestitures of proved and unproved properties — 151 37 — 188 Additions to other property and equipment — (118 ) 4 — (114 ) Other investing activities — 60 52 12 124 Net Cash Used In Investing Activities — (2,947 ) 30 12 (2,905 ) CASH FLOWS FROM FINANCING ACTIVITIES: Cash paid to repurchase noncontrolling interest of CHK C-T — — (143 ) — (143 ) Other financing activities (631 ) 387 (75 ) (37 ) (356 ) Intercompany advances, net (1,620 ) 1,620 — — — Net Cash Used In Financing Activities (2,251 ) 2,007 (218 ) (37 ) (499 ) Net decrease in cash and cash equivalents (2,251 ) 10 (83 ) (25 ) (2,349 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 1,849 $ 12 $ 1 $ (103 ) $ 1,759 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 3,423 $ 382 $ — $ 3,805 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (3,090 ) (95 ) — (3,185 ) Acquisitions of proved and unproved properties — (1,020 ) (3 ) — (1,023 ) Proceeds from divestitures of proved and unproved properties — 722 1 — 723 Additions to other property and equipment — (424 ) (251 ) — (675 ) Other investing activities — 1,162 60 — 1,222 Net Cash Used In Investing Activities — (2,650 ) (288 ) — (2,938 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 2,856 717 — 3,573 Payments on credit facilities borrowings — (2,797 ) (1,099 ) — (3,896 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,966 — 494 — 3,460 Proceeds from issuance of oilfield services term loan, net of issuance costs — — 394 — 394 Cash paid to purchase debt (3,362 ) — — — (3,362 ) Other financing activities (293 ) (1,352 ) (127 ) (11 ) (1,783 ) Intercompany advances, net (99 ) 520 (421 ) — — Net Cash Used In Financing Activities (788 ) (773 ) (42 ) (11 ) (1,614 ) Net decrease in cash and cash equivalents (788 ) — 52 (11 ) (747 ) Cash and cash equivalents, beginning of period 799 — 38 — 837 Cash and cash equivalents, end of period $ 11 $ — $ 90 $ (11 ) $ 90

Recently Issued Accounting Stan

Recently Issued Accounting Standards (Note)	9 Months Ended
	Sep. 30, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles Disclosure	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. We are evaluating the impact on our consolidated financial statements. In April 2015, the FASB issued an accounting standards update on the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements. In August 2015, the FASB issued an accounting standards update which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs update issued in April 2015. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements.

Basis of Presentation and Sum30

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2015
Accounting Policies [Abstract]
Basis of Accounting, Policy	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 and nine months ended September 30, 2015 (the "Current Quarter" and the “Current Period”, respectively) and the three and nine months ended September 30, 2014 (the "Prior Quarter" and the “Prior Period”, respectively). Chesapeake's annual report on Form 10-K for the year ended December 31, 2014 ("2014 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 and the Current Period are not necessarily indicative of the results to be expected for the full year.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	9 Months Ended
	Sep. 30, 2015
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)	9 Months Ended
	Sep. 30, 2015
Asset Impairment Charges [Abstract]
Impairment or Disposal of Long-Lived Assets, Policy	ur proved oil and natural gas properties are subject to quarterly full cost ceiling tests.

Income Taxes (Policy)

Income Taxes (Policy)	9 Months Ended
	Sep. 30, 2015
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 such taxable income is generated, to determine whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

Recently Issued Accounting St34

Recently Issued Accounting Standards (Policies)	9 Months Ended
	Sep. 30, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements, Policy	Recently Issued Accounting Standards In May 2014, the Financial Accounting Standards Board (FASB) issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016, with early application not permitted. In July 2015, the FASB approved a one-year deferral of the effective date as well as permission to early adopt the new revenue recognition standard as of the original effective date. We are evaluating the impact on our consolidated financial statements. In April 2015, the FASB issued an accounting standards update on the presentation of debt issuance costs. The update requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The recognition and measurement guidance for debt issuance costs is not affected by the update. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements. In August 2015, the FASB issued an accounting standards update which allows for line-of-credit arrangements to be handled consistently with the presentation of debt issuance costs update issued in April 2015. For public entities, the guidance is effective for reporting periods beginning after December 15, 2015, and it is not expected to have a material impact on our consolidated financial statements.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2015
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]
Antidilutive Securities Excluded From Computation Of Earnings Per Share	For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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 September 30, 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 Three Months Ended September 30, 2014 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 $ 3 3 Nine Months Ended September 30, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 64 59 5.75% cumulative convertible preferred stock (series A) $ 47 42 5.00% cumulative convertible preferred stock (series 2005B) $ 8 6 4.50% cumulative convertible preferred stock $ 9 6 Participating securities $ — 1 Nine Months Ended September 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 64 59 5.75% cumulative convertible preferred stock (series A) $ 47 42 5.00% cumulative convertible preferred stock (series 2005B) $ 8 6 4.50% cumulative convertible preferred stock $ 9 6 Participating securities $ 14 3

Debt (Tables)

Debt (Tables)	9 Months Ended
	Sep. 30, 2015
Debt Disclosure [Abstract]
Schedule of Debt	Our long-term debt consisted of the following as of September 30, 2015 and December 31, 2014: September 30, December 31, ($ in millions) 3.25% senior notes due 2016 $ 500 $ 500 6.25% euro-denominated senior notes due 2017 (a) 384 416 6.5% senior notes due 2017 660 660 7.25% senior notes due 2018 669 669 Floating rate senior notes due 2019 1,500 1,500 6.625% senior notes due 2020 1,300 1,300 6.875% senior notes due 2020 500 500 6.125% senior notes due 2021 1,000 1,000 5.375% senior notes due 2021 700 700 4.875% senior notes due 2022 1,500 1,500 5.75% senior notes due 2023 1,100 1,100 2.75% contingent convertible senior notes due 2035 (b) 396 396 2.5% contingent convertible senior notes due 2037 (b) 1,168 1,168 2.25% contingent convertible senior notes due 2038 (b) 347 347 Revolving credit facility — — Discount on senior notes (c) (165 ) (231 ) Interest rate derivatives (d) 8 10 Total debt, net 11,567 11,535 Less current maturities of long-term debt, net (e) (893 ) (381 ) Total long-term debt, net $ 10,674 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.1177 to €1.00 and $1.2098 to €1.00 as of September 30, 2015 and December 31, 2014, 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. The first put date, for the 2.75% Contingent Convertible Senior Notes due 2035 (the 2035 Notes), is November 15, 2015. As required by the terms of the indenture for the 2035 Notes, on October 1, 2015, we issued a notice to the holders of the 2035 Notes allowing each holder an opportunity to require us to repurchase some or all of its notes on November 15, 2015. As a result, we may be required to repurchase some or all of the 2035 Notes outstanding on November 15, 2015. 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 third quarter of 2015, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2015 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 or 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, 2015, 2020, 2025, 2030 $ 45.14 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 $ 100.35 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. Beginning December 1, 2015, we may redeem any 2035 Notes that have not been put to us and repurchased as described above under Holders’ Demand Repurchase Rights . (c) Discount as of September 30, 2015 and December 31, 2014 included $160 million and $224 million , respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. (d) See Interest Rate Derivatives in Note 8 for further discussion related to these instruments. (e) As of September 30, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016 and 2035 Notes. As discussed in footnote (b) above, the holders of our 2035 Notes could exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the principal amount of the notes. As of September 30, 2015 and December 31, 2014, current maturities of long-term debt, net reflects $3 million and $15 million , respectively, of discount associated with the equity component of the 2035 Notes.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. September 30, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 893 $ 881 $ 381 $ 396 Long-term debt (Level 1) $ 10,666 $ 8,043 $ 11,144 $ 11,656

Contingencies and Commitments37

Contingencies and Commitments (Tables)	9 Months Ended
	Sep. 30, 2015
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. September 30, ($ in millions) 2015 $ 461 2016 1,927 2017 1,939 2018 1,741 2019 1,452 2020 – 2099 6,828 Total $ 14,348

Other Liabilities (Tables)

Other Liabilities (Tables)	9 Months Ended
	Sep. 30, 2015
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	Other current liabilities as of September 30, 2015 and December 31, 2014 are detailed below. September 30, December 31, ($ in millions) Revenues and royalties due others $ 627 $ 1,176 Accrued drilling and production costs 231 385 Joint interest prepayments received 181 189 Accrued compensation and benefits 295 344 Other accrued taxes 105 55 Accrued dividends 43 101 Bank of New York Mellon legal accrual 439 100 Royalty settlement — 119 Other 453 592 Total other current liabilities $ 2,374 $ 3,061
Other Long-Term Liabilities	Other long-term liabilities as of September 30, 2015 and December 31, 2014 are detailed below. September 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 198 $ 220 CHK C-T ORRI conveyance obligation (b) — 135 Financing obligations 29 30 Unrecognized tax benefits 25 45 Other 135 249 Total other long-term liabilities $ 387 $ 679 ____________________________________________ (a) $20 million and $14 million of the total $218 million and $234 million obligations are recorded in other current liabilities as of September 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation. (b) $23 million of the total $158 million obligation is recorded in other current liabilities as of December 31, 2014. In the Current Quarter, we sold the oil and natural gas properties held by CHK Cleveland Tonkawa, L.L.C. (CHK C-T) and eliminated our ORRI obligation attributable to CHK C-T. See Noncontrolling Interests in Note 6 for further discussion of the transaction.

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2015
Equity [Abstract]
Common Stock	The following is a summary of the changes in our common shares issued for the Current Period and the Prior Period: Nine Months Ended 2015 2014 (in thousands) Shares issued as of January 1 664,944 666,192 Restricted stock issuances (net of forfeitures and cancellations) (a) 85 (2,413 ) Stock option exercises 14 1,267 Shares issued as of September 30 665,043 665,046 ___________________________________________ (a) The Prior Period reflects forfeitures upon the June 2014 spin-off of our oilfield services business.
Schedule of Stock by Class	The following reflects the shares outstanding of our preferred stock for the Current Period and the Prior Period: 5.75% 5.75% (A) 4.50% 5.00% (2005B) (in thousands) Shares outstanding as of January 1, 2015 and 2014 and shares outstanding as of September 30, 2015 and 2014 1,497 1,100 2,559 2,096
Schedule of Accumulated Other Comprehensive Income (Loss)	For the Current Period and the Prior Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below. Cash Flow Hedges Investments Net Change ($ in millions) Balance, December 31, 2014 $ (143 ) $ — $ (143 ) Other comprehensive income before reclassifications 6 — 6 Amounts reclassified from accumulated other comprehensive income 18 — 18 Net other comprehensive income 24 — 24 Balance, September 30, 2015 $ (119 ) $ — $ (119 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 3 — 3 Amounts reclassified from accumulated other comprehensive income 13 (5 ) 8 Net other comprehensive income 16 (5 ) 11 Balance, September 30, 2014 $ (151 ) $ — $ (151 )
Reclassification out of Accumulated Other Comprehensive Income	For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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 September 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 5 Total reclassifications for the period, net of tax $ 5 Three Months Ended September 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 3 Total reclassifications for the period, net of tax $ 3 Nine Months Ended September 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 18 Total reclassifications for the period, net of tax $ 18 Nine Months Ended September 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 13 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 8
Distributions Made to Limited Partner, by Distribution	For the Current Period and the Prior Period, the Trust declared and paid the following distributions: Production Period Distribution Date Cash Distribution per Common Unit Cash Distribution per Subordinated Unit March 2015 – May 2015 August 31, 2015 $ 0.3579 $ — December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — March 2014 – May 2014 August 29, 2014 $ 0.5796 $ — December 2013 – February 2014 May 30, 2014 $ 0.6454 $ — September 2013 – November 2013 March 3, 2014 $ 0.6624 $ —

Share-Based Compensation (Table

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Schedule of Share-Based Compensation, Restricted Stock and Restricted Stock Units Activity	A summary of the changes in unvested restricted stock during the Current Period is presented below. Shares of Unvested Restricted Stock Weighted Average Grant Date Fair Value (in thousands) Unvested restricted stock as of January 1, 2015 10,091 $ 21.20 Granted 7,016 $ 13.97 Vested (4,025 ) $ 21.78 Forfeited (899 ) $ 17.21 Unvested restricted stock as of September 30, 2015 12,183 $ 17.14
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 Period: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 % 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 46.36 % Risk-free interest rate 0.71 % Dividend yield for value of awards — %
Schedule of Share-Based Compensation, Stock Options, Activity	The following table provides information related to stock option activity for the Current Period: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ in millions) Outstanding at January 1, 2015 4,599 $ 19.55 7.03 $ 5 Granted 1,208 $ 18.37 Exercised (14 ) $ 18.13 $ — Expired (213 ) $ 18.54 Forfeited — $ — Outstanding at September 30, 2015 5,580 $ 19.33 5.83 $ — Exercisable at September 30, 2015 2,248 $ 19.50 4.86 $ — ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
Equity-Classified Stock-Based Compensation	We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 9 $ 12 $ 33 $ 36 Oil and natural gas properties 3 6 18 22 Oil, natural gas and NGL production expenses 4 5 14 13 Marketing, gathering and compression expenses — 2 3 5 Oilfield services expenses — — — 5 Total $ 16 $ 25 $ 68 $ 81 We recognized the following compensation costs (credits) related to PSUs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (2 ) $ (12 ) $ (16 ) $ (2 ) Restructuring and other termination costs (1 ) (17 ) (16 ) (11 ) Marketing, gathering and compression — (1 ) (1 ) — Oil and natural gas properties — — (1 ) 3 Total $ (3 ) $ (30 ) $ (34 ) $ (10 )
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 Period: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 % 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 46.36 % Risk-free interest rate 0.71 % Dividend yield for value of awards — %
Schedule of Nonvested Performance-based Units Activity	The following table presents a summary of our 2013, 2014 and 2015 PSU awards: Units Fair Value as of Grant Date Fair Value (a) Liability for Vested Amount (a) ($ in millions) 2013 Awards: Payable 2016 1,701,941 $ 35 $ 9 $ 9 2014 Awards: Payable 2017 609,637 $ 16 $ 1 $ 1 2015 Awards: Payable 2018 696,683 $ 13 $ 4 $ 2 ___________________________________________ (a) As of September 30, 2015 .
Liability-Classified Stock-Based Compensation	We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 9 $ 12 $ 33 $ 36 Oil and natural gas properties 3 6 18 22 Oil, natural gas and NGL production expenses 4 5 14 13 Marketing, gathering and compression expenses — 2 3 5 Oilfield services expenses — — — 5 Total $ 16 $ 25 $ 68 $ 81 We recognized the following compensation costs (credits) related to PSUs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (2 ) $ (12 ) $ (16 ) $ (2 ) Restructuring and other termination costs (1 ) (17 ) (16 ) (11 ) Marketing, gathering and compression — (1 ) (1 ) — Oil and natural gas properties — — (1 ) 3 Total $ (3 ) $ (30 ) $ (34 ) $ (10 )

Derivative and Hedging Activi41

Derivative and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions	The estimated fair values of our oil and natural gas derivative instrument assets (liabilities) as of September 30, 2015 and December 31, 2014 are provided below. September 30, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 8.0 $ 161 12.5 $ 471 Three-way collars 1.1 11 4.4 40 Call options 18.1 (9 ) 35.8 (89 ) Basis protection swaps 1.6 — — — Total oil 28.8 $ 163 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 295 $ 174 275 $ 281 Three-way collars 36 28 207 165 Call options 193 (107 ) 193 (170 ) Basis protection swaps 75 (4 ) 60 23 Total natural gas 599 $ 91 735 $ 299 Total estimated fair value $ 254 $ 721
Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets	The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2015 and December 31, 2014 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 September 30, 2015 Commodity Contracts: Short-term derivative asset $ 370 $ (71 ) $ 299 Long-term derivative asset 12 (3 ) 9 Short-term derivative liability (95 ) 71 (24 ) Long-term derivative liability (33 ) 3 (30 ) Total commodity contracts 254 — 254 Foreign Currency Contracts: (a) Long-term derivative liability (76 ) — (76 ) Total foreign currency contracts (76 ) — (76 ) Supply Contracts: Short-term derivative asset 43 — 43 Long-term derivative asset 248 — 248 Total supply contracts 291 — 291 Total derivatives $ 469 $ — $ 469 Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet As of December 31, 2014 Commodity Contracts: Short-term derivative asset $ 974 $ (95 ) $ 879 Long-term derivative asset 16 (10 ) 6 Short-term derivative liability (105 ) 95 (10 ) Long-term derivative liability (163 ) 10 (153 ) Total commodity contracts 722 — 722 Interest Rate Contracts: Short-term derivative liability (5 ) — (5 ) Long-term derivative liability (12 ) — (12 ) Total interest rate contracts (17 ) — (17 ) Foreign Currency Contracts: (a) Long-term derivative liability (53 ) — (53 ) Total foreign currency contracts (53 ) — (53 ) Total derivatives $ 652 $ — $ 652 ____________________________________________ (a) Designated as cash flow hedging instruments.
Schedule of Derivative Instruments, Natural Gas and Oil Sales	The components of marketing, gathering and compression revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression revenues (a) $ 1,943 $ 3,362 $ 5,703 $ 9,543 Gains on undesignated supply contract derivatives 70 — 290 — Total marketing, gathering and compression revenues $ 2,013 $ 3,362 $ 5,993 $ 9,543 ____________________________________________ (a) Current Quarter and Current Period settlements of $41 million and $77 million , respectively, on supply contracts accounted for as derivatives are included in marketing, gathering and compression revenues. The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL revenues $ 653 $ 1,777 $ 2,353 $ 5,842 Gains (losses) on undesignated oil and natural gas derivatives 234 569 369 (5 ) Losses on terminated cash flow hedges (7 ) (5 ) (29 ) (25 ) Total oil, natural gas and NGL revenues $ 880 $ 2,341 $ 2,693 $ 5,812
Schedule of Derivative Instruments, Marketing, Gathering and Compression Sales	The components of marketing, gathering and compression revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression revenues (a) $ 1,943 $ 3,362 $ 5,703 $ 9,543 Gains on undesignated supply contract derivatives 70 — 290 — Total marketing, gathering and compression revenues $ 2,013 $ 3,362 $ 5,993 $ 9,543 ____________________________________________ (a) Current Quarter and Current Period settlements of $41 million and $77 million , respectively, on supply contracts accounted for as derivatives are included in marketing, gathering and compression revenues. The components of oil, natural gas and NGL revenues for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL revenues $ 653 $ 1,777 $ 2,353 $ 5,842 Gains (losses) on undesignated oil and natural gas derivatives 234 569 369 (5 ) Losses on terminated cash flow hedges (7 ) (5 ) (29 ) (25 ) Total oil, natural gas and NGL revenues $ 880 $ 2,341 $ 2,693 $ 5,812
Interest Income And Interest Expense Disclosure	The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Interest expense on senior notes $ 171 $ 170 $ 513 $ 534 Interest expense on term loan — — — 36 Amortization of loan discount, issuance costs and other 14 9 37 44 Interest expense on credit facilities 2 6 8 22 Gains on terminated fair value hedges — — (2 ) (2 ) (Gains) losses on undesignated interest rate derivatives — 2 (10 ) (48 ) Capitalized interest (99 ) (170 ) (336 ) (504 ) Total interest expense $ 88 $ 17 $ 210 $ 82
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 September 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (211 ) $ (131 ) $ (243 ) $ (154 ) Net change in fair value 12 7 — — Losses reclassified to income 7 5 5 3 Balance, end of period $ (192 ) $ (119 ) $ (238 ) $ (151 ) Nine Months Ended September 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (231 ) $ (143 ) $ (269 ) $ (167 ) Net change in fair value 10 6 6 3 Losses reclassified to income 29 18 25 13 Balance, end of period $ (192 ) $ (119 ) $ (238 ) $ (151 )
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 September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 343 $ 39 $ 382 Commodity liabilities — (12 ) (116 ) (128 ) Interest rate liabilities — — — — Foreign currency liabilities — (76 ) — (76 ) Supply contract assets — — 291 291 Total derivatives $ — $ 255 $ 214 $ 469 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 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 September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Financial Assets (Liabilities): Other current assets $ 58 $ — $ — $ 58 Other current liabilities (60 ) — — (60 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 )
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	A summary of the changes in the fair values of Chesapeake’s financial assets (liabilities) classified as Level 3 during the Current Period and the Prior Period is presented below. Commodity Derivatives Supply Contracts ($ in millions) Beginning balance as of January 1, 2015 $ (54 ) $ 1 Total gains (losses) (unrealized): Included in earnings (a) 99 281 Total purchases, issuances, sales and settlements: Settlements (122 ) 9 Ending balance as of September 30, 2015 $ (77 ) $ 291 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (unrealized): Included in earnings (a) 53 — Total purchases, issuances, sales and settlements: Settlements 124 — Transfers (b) (4 ) — Ending balance as of September 30, 2014 $ (305 ) $ — ___________________________________________ (a) Oil, Natural Gas and NGL Sales Marketing, Gathering and Compression Revenue 2015 2014 2015 2014 ($ in millions) Total gains (losses) included in earnings for the period $ 99 $ 53 $ 281 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 72 $ 60 $ 281 $ — (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 September 30, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value September 30, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 23.69% – 37.51% 31.70% $ 2 Supply contracts (b) Oil price volatility curves 20.22% – 44.86% 23.82% $ 291 Natural gas trades (a) Natural gas price volatility curves 19.76% – 61.06% 31.31% $ (79 ) ___________________________________________ (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 42

Oil and Natural Gas Property Transactions (Tables)	9 Months Ended
	Sep. 30, 2015
Property, Plant and Equipment [Abstract]
VPP Transactions	As of September 30, 2015 , our outstanding VPPs consisted of the following: Volume Sold VPP # Date of VPP Location Proceeds Oil Natural Gas NGL Total ($ in millions) (mmbbl) (bcf) (mmbbl) (bcfe) 10 March 2012 Anadarko Basin Granite Wash $ 744 3.0 87 9.2 160 9 May 2011 Mid-Continent 853 1.7 138 4.8 177 4 December 2008 Anadarko and Arkoma Basins 412 0.5 95 — 98 3 August 2008 Anadarko Basin 600 — 93 — 93 2 May 2008 Texas, Oklahoma and Kansas 622 — 94 — 94 1 December 2007 Kentucky and West Virginia 1,100 — 208 — 208 $ 4,331 5.2 715 14.0 830
VPP Volumes Produced During Period	The volumes produced on behalf of our VPP buyers during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows: Three Months Ended September 30, 2015 Three Months Ended September 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 76.0 2.1 253.3 4.0 98.0 2.6 314.5 5.0 9 41.4 3.6 92.9 4.3 46.1 3.8 101.5 4.7 8 (a) — 8.9 — 8.9 — 14.8 — 14.8 6 (b) — — — — 6.0 1.1 — 1.1 5 (b) — — — — 4.2 1.2 — 1.2 4 10.5 2.0 — 2.0 11.9 2.2 — 2.3 3 — 1.6 — 1.6 — 1.8 — 1.8 2 — 1.0 — 1.0 — 1.1 — 1.1 1 — 3.2 — 3.2 — 3.4 — 3.4 127.9 22.4 346.2 25.0 166.2 32.0 416.0 35.4 Nine Months Ended September 30, 2015 Nine Months Ended September 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 237.0 6.5 798.3 12.7 310.0 8.1 989.6 15.8 9 127.5 10.8 284.8 13.2 142.6 11.7 311.9 14.4 8 (a) — 36.5 — 36.5 — 45.7 — 45.7 6 (b) — — — — 18.0 3.3 — 3.4 5 (b) — — — — 16.5 4.6 — 4.7 4 32.2 6.1 — 6.2 36.5 6.8 — 7.0 3 — 4.9 — 4.9 — 5.5 — 5.5 2 — 3.1 — 3.1 — 5.1 — 5.1 1 — 10.0 — 10.0 — 10.4 — 10.4 396.7 77.9 1,083.1 86.6 523.6 101.2 1,301.5 112.0 ____________________________________________ (a) VPP #8 expired in August 2015. (b) In 2014, we divested the properties associated with VPP #5 and VPP #6.
VPP Volumes Remaining to Be Delivered	The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2015 were as follows: Volume Remaining as of September 30, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 77 1.1 31.5 3.9 61.3 9 65 0.7 62.5 1.7 76.6 4 15 — 9.3 — 9.6 3 46 — 19.1 — 19.1 2 43 — 10.8 — 10.8 1 87 — 81.6 — 81.6 1.8 214.8 5.6 259.0

Investments (Tables)

Investments (Tables)	9 Months Ended
	Sep. 30, 2015
Investments [Abstract]
Equity Method Investments	A summary of our investments, including our approximate ownership percentage and carrying value as of September 30, 2015 and December 31, 2014 , is presented below. Approximate Ownership % Carrying Value Accounting Method September 30, December 31, September 30, December 31, ($ in millions) FTS International, Inc. Equity 30% 30% $ 88 $ 116 Sundrop Fuels, Inc. Equity 56% 56% 119 130 Other — —% —% 18 19 Total investments $ 225 $ 265

Other Property and Equipment (T

Other Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2015
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]
Property, Plant and Equipment	A summary by asset class of (gains) or losses on sales of fixed assets for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows: Three Months Ended Nine Months Ended 2015 2014 2015 2014 ($ in millions) Natural gas compressors $ (1 ) $ (75 ) $ (1 ) $ (195 ) Gathering systems and treating plants 1 (5 ) 1 8 Oilfield services equipment — — — (7 ) Buildings and land (1 ) (6 ) — (5 ) Other — — 3 (2 ) Total net (gains) losses on sales of fixed assets $ (1 ) $ (86 ) $ 3 $ (201 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 343 $ 39 $ 382 Commodity liabilities — (12 ) (116 ) (128 ) Interest rate liabilities — — — — Foreign currency liabilities — (76 ) — (76 ) Supply contract assets — — 291 291 Total derivatives $ — $ 255 $ 214 $ 469 As of December 31, 2014 Derivative Assets (Liabilities): Commodity assets $ — $ 784 $ 205 $ 989 Commodity liabilities — (9 ) (259 ) (268 ) Interest rate liabilities — (17 ) — (17 ) Foreign currency liabilities — (53 ) — (53 ) Supply contract assets — — 1 1 Total derivatives $ — $ 705 $ (53 ) $ 652 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 September 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of September 30, 2015 Financial Assets (Liabilities): Other current assets $ 58 $ — $ — $ 58 Other current liabilities (60 ) — — (60 ) Total $ (2 ) $ — $ — $ (2 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 )

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2015
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Schedule of Segment Reporting Information, by Segment	The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Three Months Ended September 30, 2015 Revenues $ 853 $ 3,059 $ — $ — $ (1,019 ) $ 2,893 Intersegment revenues 27 (1,046 ) — — 1,019 — Total revenues $ 880 $ 2,013 $ — $ — $ — $ 2,893 Income (Loss) Before Income Taxes $ (5,625 ) $ 70 $ — $ (37 ) $ 16 $ (5,576 ) Three Months Ended September 30, 2014 Revenues $ 2,341 $ 5,512 $ — $ — $ (2,150 ) $ 5,703 Intersegment revenues — (2,150 ) — — 2,150 — Total revenues $ 2,341 $ 3,362 $ — $ — $ — $ 5,703 Income (Loss) Before Income Taxes $ 987 $ 113 $ — $ (63 ) $ 92 $ 1,129 Nine Months Ended September 30, 2015 Revenues $ 2,614 $ 9,476 $ — $ — $ (3,404 ) $ 8,686 Intersegment revenues 79 (3,483 ) — — 3,404 — Total revenues $ 2,693 $ 5,993 $ — $ — $ — $ 8,686 Income (Loss) Before Income Taxes $ (16,759 ) $ 208 $ — $ (82 ) $ 369 $ (16,264 ) Nine Months Ended September 30, 2014 Revenues $ 5,812 $ 16,289 $ 1,060 $ 30 $ (7,290 ) $ 15,901 Intersegment revenues — (6,746 ) (544 ) — 7,290 — Total revenues $ 5,812 $ 9,543 $ 516 $ 30 $ — $ 15,901 Income (Loss) Before Income Taxes $ 2,089 $ 325 $ (16 ) $ (24 ) $ (128 ) $ 2,246 As of September 30, 2015 Total Assets $ 15,646 $ 1,711 $ — $ 4,342 $ (413 ) $ 21,286 As of December 31, 2014 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751

Condensed Consolidating Finan47

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Balance Sheet	CONDENSED CONSOLIDATING BALANCE SHEET AS OF SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 1,849 $ 12 $ 1 $ (103 ) $ 1,759 Restricted cash — — — — — Other 69 1,736 15 — 1,820 Intercompany receivable, net 24,909 — 457 (25,366 ) — Total Current Assets 26,827 1,748 473 (25,469 ) 3,579 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 13,503 98 1,125 14,726 Other property and equipment, net — 2,139 — — 2,139 Property and equipment held for sale, net — 94 — — 94 Total Property and Equipment, Net — 15,736 98 1,125 16,959 LONG-TERM ASSETS: Other assets 112 626 10 — 748 Investments in subsidiaries and intercompany advances (10,358 ) 788 — 9,570 — TOTAL ASSETS $ 16,581 $ 18,898 $ 581 $ (14,774 ) $ 21,286 CURRENT LIABILITIES: Current liabilities $ 1,529 $ 3,118 $ 13 $ (103 ) $ 4,557 Intercompany payable, net — 24,788 — (24,788 ) — Total Current Liabilities 1,529 27,906 13 (24,891 ) 4,557 LONG-TERM LIABILITIES: Long-term debt, net 10,674 — — — 10,674 Deferred income tax liabilities (5 ) 516 32 31 574 Other long-term liabilities 101 834 — — 935 Total Long-Term Liabilities 10,770 1,350 32 31 12,183 EQUITY: Chesapeake stockholders’ equity 4,282 (10,358 ) 536 9,822 4,282 Noncontrolling interests — — — 264 264 Total Equity 4,282 (10,358 ) 536 10,086 4,546 TOTAL LIABILITIES AND EQUITY $ 16,581 $ 18,898 $ 581 $ (14,774 ) $ 21,286 CONDENSED CONSOLIDATING BALANCE SHEET AS OF DECEMBER 31, 2014 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 4,100 $ 2 $ 84 $ (78 ) $ 4,108 Restricted cash — — 38 — 38 Other 55 3,174 93 — 3,322 Intercompany receivable, net 24,527 — 341 (24,868 ) — Total Current Assets 28,682 3,176 556 (24,946 ) 7,468 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 28,358 1,112 673 30,143 Other property and equipment, net — 2,276 3 — 2,279 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 30,727 1,115 673 32,515 LONG-TERM ASSETS: Other assets 153 618 26 (29 ) 768 Investments in subsidiaries and intercompany advances 126 467 — (593 ) — TOTAL ASSETS $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751 CURRENT LIABILITIES: Current liabilities $ 792 $ 5,081 $ 68 $ (78 ) $ 5,863 Intercompany payable, net — 24,940 — (24,940 ) — Total Current Liabilities 792 30,021 68 (25,018 ) 5,863 LONG-TERM LIABILITIES: Long-term debt, net 11,154 — — — 11,154 Deferred income tax liabilities — 3,751 234 200 4,185 Other long-term liabilities 112 1,090 142 — 1,344 Total Long-Term Liabilities 11,266 4,841 376 200 16,683 EQUITY: Chesapeake stockholders’ equity 16,903 126 1,253 (1,379 ) 16,903 Noncontrolling interests — — — 1,302 1,302 Total Equity 16,903 126 1,253 (77 ) 18,205 TOTAL LIABILITIES AND EQUITY $ 28,961 $ 34,988 $ 1,697 $ (24,895 ) $ 40,751
Schedule of Condensed Income Statement	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 855 $ 25 $ — $ 880 Marketing, gathering and compression — 2,013 — — 2,013 Total Revenues — 2,868 25 — 2,893 OPERATING EXPENSES: Oil, natural gas and NGL production — 245 6 — 251 Production taxes — 25 — — 25 Marketing, gathering and compression — 1,955 — — 1,955 General and administrative 1 47 1 — 49 Restructuring and other termination costs — 53 — — 53 Oil, natural gas and NGL depreciation, depletion and amortization — 478 11 (1 ) 488 Depreciation and amortization of other assets — 31 — — 31 Impairment of oil and natural gas properties — 5,412 37 (33 ) 5,416 Impairments of fixed assets and other — 79 — — 79 Net gains on sales of fixed assets — (1 ) — — (1 ) Total Operating Expenses 1 8,324 55 (34 ) 8,346 LOSS FROM OPERATIONS (1 ) (5,456 ) (30 ) 34 (5,453 ) OTHER INCOME (EXPENSE): Interest expense (182 ) (58 ) — 152 (88 ) Losses on investments — (33 ) — — (33 ) Other income (expense) 140 (113 ) — (29 ) (2 ) Equity in net earnings (losses) of subsidiary (4,594 ) (50 ) — 4,644 — Total Other Expense (4,636 ) (254 ) — 4,767 (123 ) LOSS BEFORE INCOME TAXES (4,637 ) (5,710 ) (30 ) 4,801 (5,576 ) INCOME TAX BENEFIT (EXPENSE) 15 (985 ) 7 26 (937 ) NET LOSS (4,652 ) (4,725 ) (37 ) 4,775 (4,639 ) Net income attributable to noncontrolling interests — — — (13 ) (13 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (4,652 ) (4,725 ) (37 ) 4,762 (4,652 ) Other comprehensive income 8 4 — — 12 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (4,644 ) $ (4,721 ) $ (37 ) $ 4,762 $ (4,640 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 2,223 $ 118 $ — $ 2,341 Marketing, gathering and compression — 3,361 1 — 3,362 Total Revenues — 5,584 119 — 5,703 OPERATING EXPENSES: Oil, natural gas and NGL production — 289 9 — 298 Production taxes — 61 1 — 62 Marketing, gathering and compression — 3,368 1 — 3,369 General and administrative — 59 1 — 60 Restructuring and other termination costs — (14 ) — — (14 ) Provision for legal contingencies — 100 — — 100 Oil, natural gas and NGL depreciation, depletion and amortization — 662 44 (18 ) 688 Depreciation and amortization of other assets — 37 — — 37 Impairment of oil and natural gas — — 104 (104 ) — Impairments of fixed assets and other — 15 — — 15 Net gains on sales of fixed assets — (86 ) — — (86 ) Total Operating Expenses — 4,491 160 (122 ) 4,529 INCOME (LOSS) FROM OPERATIONS — 1,093 (41 ) 122 1,174 OTHER INCOME (EXPENSE): Interest expense (178 ) (11 ) — 172 (17 ) Losses on investments — (27 ) — — (27 ) Other income 56 119 (4 ) (172 ) (1 ) Equity in net earnings (losses) of subsidiary 737 (58 ) — (679 ) — Total Other Income (Expense) 615 23 (4 ) (679 ) (45 ) INCOME BEFORE INCOME TAXES 615 1,116 (45 ) (557 ) 1,129 INCOME TAX EXPENSE (BENEFIT) (47 ) 454 (17 ) 47 437 NET INCOME (LOSS) 662 662 (28 ) (604 ) 692 Net income attributable to noncontrolling interests — — — (30 ) (30 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 662 662 (28 ) (634 ) 662 Other comprehensive income (loss) — 3 — — 3 COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 662 $ 665 $ (28 ) $ (634 ) $ 665 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 2,583 $ 110 $ — $ 2,693 Marketing, gathering and compression — 5,993 — — 5,993 Total Revenues — 8,576 110 — 8,686 OPERATING EXPENSES: Oil, natural gas and NGL production — 799 27 — 826 Production taxes — 85 2 — 87 Marketing, gathering and compression — 5,750 1 — 5,751 General and administrative 3 168 3 — 174 Restructuring and other termination costs — 39 — — 39 Provision for legal contingencies 339 20 — — 359 Oil, natural gas and NGL depreciation, depletion and amortization — 1,727 66 (20 ) 1,773 Depreciation and amortization of other assets — 100 — — 100 Impairment of oil and natural gas properties — 15,395 443 (431 ) 15,407 Impairments of fixed assets and other — 167 — — 167 Net losses on sales of fixed assets — 3 — — 3 Total Operating Expenses 342 24,253 542 (451 ) 24,686 LOSS FROM OPERATIONS (342 ) (15,677 ) (432 ) 451 (16,000 ) OTHER INCOME (EXPENSE): Interest expense (532 ) (133 ) — 455 (210 ) Losses on investments — (57 ) — — (57 ) Other income 100 5 — (102 ) 3 Equity in net earnings (losses) of subsidiary (11,908 ) (381 ) — 12,289 — Total Other Expense (12,340 ) (566 ) — 12,642 (264 ) LOSS BEFORE INCOME TAXES (12,682 ) (16,243 ) (432 ) 13,093 (16,264 ) INCOME TAX BENEFIT (182 ) (3,720 ) (101 ) 189 (3,814 ) NET LOSS (12,500 ) (12,523 ) (331 ) 12,904 (12,450 ) Net income attributable to noncontrolling interests — — — (50 ) (50 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (12,500 ) (12,523 ) (331 ) 12,854 (12,500 ) Other comprehensive income (loss) 6 18 — — 24 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (12,494 ) $ (12,505 ) $ (331 ) $ 12,854 $ (12,476 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS NINE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 5,505 $ 310 $ (3 ) $ 5,812 Marketing, gathering and compression — 9,539 4 — 9,543 Oilfield services — 41 983 (478 ) 546 Total Revenues — 15,085 1,297 (481 ) 15,901 OPERATING EXPENSES: Oil, natural gas and NGL production — 837 31 — 868 Production taxes — 181 4 — 185 Marketing, gathering and compression — 9,512 3 — 9,515 Oilfield services — 53 769 (391 ) 431 General and administrative — 182 47 — 229 Restructuring and other termination costs — 9 3 — 12 Provision for legal contingencies — 100 — — 100 Oil, natural gas and NGL depreciation, depletion and amortization — 1,910 124 (57 ) 1,977 Depreciation and amortization of other assets — 116 142 (64 ) 194 Impairment of oil and natural gas — — 202 (202 ) — Impairments of fixed assets and other — 52 23 — 75 Net gains on sales of fixed assets — (194 ) (7 ) — (201 ) Total Operating Expenses — 12,758 1,341 (714 ) 13,385 INCOME (LOSS) FROM OPERATIONS — 2,327 (44 ) 233 2,516 OTHER INCOME (EXPENSE): Interest expense (524 ) (14 ) (42 ) 498 (82 ) Losses on investments — (69 ) (5 ) 2 (72 ) Net gain on sales of investments — 67 — — 67 Losses on purchases of debt (195 ) — — — (195 ) Other income (expense) 535 3 (2 ) (524 ) 12 Equity in net earnings (losses) of subsidiary 1,391 (167 ) — (1,224 ) — Total Other Income (Expense) 1,207 (180 ) (49 ) (1,248 ) (270 ) INCOME (LOSS) BEFORE INCOME TAXES 1,207 2,147 (93 ) (1,015 ) 2,246 INCOME TAX EXPENSE (BENEFIT) (70 ) 884 (36 ) 81 859 NET INCOME (LOSS) 1,277 1,263 (57 ) (1,096 ) 1,387 Net income attributable to noncontrolling interests — — — (110 ) (110 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 1,277 1,263 (57 ) (1,206 ) 1,277 Other comprehensive income 3 8 — — 11 COMPREHENSIVE INCOME (LOSS) $ 1,280 $ 1,271 $ (57 ) $ (1,206 ) $ 1,288
Schedule of Condensed Cash Flow Statement	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 950 $ 105 $ — $ 1,055 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,633 ) (63 ) — (2,696 ) Acquisitions of proved and unproved properties — (407 ) — — (407 ) Proceeds from divestitures of proved and unproved properties — 151 37 — 188 Additions to other property and equipment — (118 ) 4 — (114 ) Other investing activities — 60 52 12 124 Net Cash Used In Investing Activities — (2,947 ) 30 12 (2,905 ) CASH FLOWS FROM FINANCING ACTIVITIES: Cash paid to repurchase noncontrolling interest of CHK C-T — — (143 ) — (143 ) Other financing activities (631 ) 387 (75 ) (37 ) (356 ) Intercompany advances, net (1,620 ) 1,620 — — — Net Cash Used In Financing Activities (2,251 ) 2,007 (218 ) (37 ) (499 ) Net decrease in cash and cash equivalents (2,251 ) 10 (83 ) (25 ) (2,349 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 1,849 $ 12 $ 1 $ (103 ) $ 1,759 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS NINE MONTHS ENDED SEPTEMBER 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 3,423 $ 382 $ — $ 3,805 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (3,090 ) (95 ) — (3,185 ) Acquisitions of proved and unproved properties — (1,020 ) (3 ) — (1,023 ) Proceeds from divestitures of proved and unproved properties — 722 1 — 723 Additions to other property and equipment — (424 ) (251 ) — (675 ) Other investing activities — 1,162 60 — 1,222 Net Cash Used In Investing Activities — (2,650 ) (288 ) — (2,938 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 2,856 717 — 3,573 Payments on credit facilities borrowings — (2,797 ) (1,099 ) — (3,896 ) Proceeds from issuance of senior notes, net of discount and offering costs 2,966 — 494 — 3,460 Proceeds from issuance of oilfield services term loan, net of issuance costs — — 394 — 394 Cash paid to purchase debt (3,362 ) — — — (3,362 ) Other financing activities (293 ) (1,352 ) (127 ) (11 ) (1,783 ) Intercompany advances, net (99 ) 520 (421 ) — — Net Cash Used In Financing Activities (788 ) (773 ) (42 ) (11 ) (1,614 ) Net decrease in cash and cash equivalents (788 ) — 52 (11 ) (747 ) Cash and cash equivalents, beginning of period 799 — 38 — 837 Cash and cash equivalents, end of period $ 11 $ — $ 90 $ (11 ) $ 90

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		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments		$ 3	$ 0	$ 14
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount		3	1	3
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 21	$ 21	$ 64	$ 64
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	59	59	59	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	$ 47	$ 47
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	42	42	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	$ 8	$ 8
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	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	$ 9	$ 9
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	6	6

Debt - Long-Term Debt Table (De

Debt - Long-Term Debt Table (Details) $ / shares in Units, $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)$ / shares$ / €	Dec. 31, 2014USD ($)$ / €	Dec. 31, 2006USD ($)$ / €
Long-Term Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	$ (165)	$ (231)
Long-term Debt	11,567	11,535
Current maturities of long-term debt, net	(893)	(381)
Long-term debt, net	$ 10,674	11,154
Credit Facility Commitment Period	10 years
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	(160)	(224)
Line of Credit [Member] | Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 0	0
Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Percentage Of Principal Amount Of Notes For Repurchase Requirement Of Contingent Convertible Senior Notes	100.00%
Credit Facility Commitment Period	10 years
Debt Instrument, Convertible, Terms of Conversion Feature	5 days
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed	100.00%
Debt Instrument, Redemption, Period One [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	5 years
Debt Instrument, Redemption, Period Two [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	10 years
Debt Instrument, Redemption, Period Three [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	15 years
Debt Instrument, Redemption, Period Four [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Credit Facility Commitment Period	20 years
Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 8	10
3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500	500
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]
Long-term Debt, Gross	$ 384	$ 416	$ 344
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 | $ / €	1.1177	1.2098	1.3325
Debt Instrument, Interest Rate, Stated Percentage	6.25%
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 660	$ 660
Debt Instrument, Interest Rate, Stated Percentage	6.50%
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 669	669
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,300	1,300
Debt Instrument, Interest Rate, Stated Percentage	6.625%
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500	500
Debt Instrument, Interest Rate, Stated Percentage	6.875%
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,000	1,000
Debt Instrument, Interest Rate, Stated Percentage	6.125%
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 700	700
Debt Instrument, Interest Rate, Stated Percentage	5.375%
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage	4.875%
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,100	1,100
Debt Instrument, Interest Rate, Stated Percentage	5.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Common Stock Price Conversion Thresholds | $ / shares	$ 45.14
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]
Long-term Debt, Gross	$ 396	396
Debt Instrument, Unamortized Discount	$ (3)	(15)
Debt Instrument, Interest Rate, Stated Percentage	2.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.75%
2.5% Contingent Convertible Senior Notes due 2037 [Member]
Long-Term Debt Instrument [Line Items]
Common Stock Price Conversion Thresholds | $ / shares	$ 59.44
Debt Instrument, Date of First Required Payment	Nov. 14, 2017
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,168	1,168
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	$ 100.35
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]
Long-term Debt, Gross	$ 347	$ 347
Debt Instrument, Interest Rate, Stated Percentage	2.25%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	2.25%

Debt - Long Term Debt Table (Ph

Debt - Long Term Debt Table (Phantom) (Details)	9 Months Ended
	Sep. 30, 2015
3.25% Senior Notes due 2016 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument Maturity Date	Mar. 15, 2016
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member] | Cross Currency Interest Rate Contract [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debt Instrument Maturity Date	Jan. 15, 2017
6.5% Senior Notes Due 2017 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Date	Aug. 15, 2017
7.25% Senior Notes Due 2018 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Date	Dec. 15, 2018
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument Maturity Date	Apr. 15, 2019
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.625%
Debt Instrument Maturity Date	Aug. 15, 2020
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.875%
Debt Instrument Maturity Date	Nov. 15, 2020
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.125%
Debt Instrument Maturity Date	Feb. 15, 2021
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.375%
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
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 Instrument, Interest Rate, Stated Percentage	2.75%
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 Purchased Narrative (Details) - USD ($) $ in Millions	Jul. 17, 2015	Sep. 30, 2015	Dec. 31, 2014
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		100.00%
2.5% Contingent Convertible Senior Notes due 2037 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 1,168	$ 1,168
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%
Debt Instrument, Interest Rate, Effective Percentage		8.00%
2.75% Contingent Convertible Senior Notes Due 2035 [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 396	396
Debt Instrument, Interest Rate, Stated Percentage		2.75%
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.75%
Debt Instrument, Interest Rate, Effective Percentage		6.86%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 347	$ 347
Debt Instrument, Interest Rate, Stated Percentage		2.25%
2.25% Contingent Convertible Senior Notes Due 2038 [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.25%
Debt Instrument, Interest Rate, Effective Percentage		8.00%
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		6.775%
Loss Contingency, Damages Awarded, Value	$ 380
Loss Contingency, Prejudgment Interest Awarded	$ 59
Minimum [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 50
Maximum [Member] | Convertible Debt [Member]
Long-Term Debt Instrument [Line Items]
Long-term Debt, Gross		$ 75

Debt - Revolving Credit Facilit

Debt - Revolving Credit Facility Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2017	Sep. 30, 2015	Dec. 31, 2018	Dec. 31, 2017
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Borrowing Capacity, Description		The amended credit facility provides that, while the obligations are required to be secured, (i) we have the right to incur junior lien indebtedness of up to $2.0 billion; (ii) our use of the facility will be subject to a borrowing base; (iii) the rate of interest on outstanding loans, as well as fees on undrawn commitments, will vary based on the percentage of the borrowing base used, rather than on our credit ratings; (iv) the total leverage ratio covenant will be suspended; and (v) the credit facility will be subject to a first lien secured leverage ratio and an interest rate coverage ratio (as described below). The amendment sets the borrowing base at $4.0 billion. The total commitments under the credit facility remain at $4.0 billion, subject to reduction in connection with issuances of junior lien indebtedness by us after April 15, 2016, the date of the first borrowing base redetermination. No adjustment to the total commitment will occur for any junior lien indebtedness issuance that occurs before April 15, 2016.
Line of Credit Facility, Covenant Terms		a requirement that we maintain, as of the last day of each fiscal quarter, a net debt to capitalization ratio (as defined in the amended credit agreement) that does not exceed 65%. While it is required to be secured by a portion of our oil and natural gas properties, the amended credit facility requires us to maintain, as of the last day of each fiscal quarter (i) a first lien secured leverage ratio (as defined in the amended credit agreement) of 3.5 to 1.0 through 2017 and 3.0 to 1.0 thereafter, and (ii) an interest rate coverage ratio (as defined in the amended credit agreement) of 1.1 to 1.0 through the first quarter of 2017, increasing to 1.25 to 1.0 by the end of 2017.
Revolving Credit Facility [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity		$ 4,000
Long-term Debt, Gross		0
Letters of Credit Outstanding, Amount		$ 12
Interest Rate In Addition To Federal Funds Rate		0.50%
Loans Receivable, Basis Spread on Variable Rate		1.00%
Line of Credit Facility, Guarantee Event One		cross-payment default and cross acceleration with respect to indebtedness in an aggregate principal amount of $125 million or more
Line of Credit Facility, Guarantee Event Two		bankruptcy; judgments involving liability of $125 million or more that are not paid
Line of Credit Facility, Guarantee Event Three		ERISA events
Credit Facility Default Value, Cross Payment Default and Cross Acceleration With Respect to Indebtedness Aggregate Minimum Principal Amount		$ 125
Credit Facility Default Value, Bankruptcy - Judgments Involving Liability, Minimum Principal Amount		$ 125
Revolving Credit Facility [Member] | Alternative Base Rate (ABR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End		1.00%
Revolving Credit Facility [Member] | London Interbank Offered Rate (LIBOR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End		2.00%
Revolving Credit Facility [Member] | Maximum [Member]
Long-Term Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital		0.65
Revolving Credit Facility [Member] | Junior Lien [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity		$ 2,000
Revolving Credit Facility [Member] | Senior Lien [Member]
Long-Term Debt Instrument [Line Items]
Borrowing capacity		$ 4,000
Revolving Credit Facility [Member] | First Lien Secured Leverage Ratio [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Covenant Description			3.0 to 1	3.5 to 1
Revolving Credit Facility [Member] | Interest Rate Coverage Ratio [Member] | Scenario, Forecast [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Covenant Description	1.25 to 1.0			1.1 to 1.0

Debt Debt - Spin-Off of Oilfiel

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

Debt - Fair Value of Other Fina

Debt - Fair Value of Other Financial Instruments (Table) (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	$ 893	$ 381
Long-term Debt, Fair Value	10,666	11,144
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Short-term Debt, Fair Value	881	396
Long-term Debt, Fair Value	$ 8,043	$ 11,656

Contingencies - Narrative (Deta

Contingencies - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Loss Contingencies [Line Items]
Provision for legal contingencies	$ 0	$ 100	$ 359	$ 100
Redemption of 2019 Notes [Member]
Loss Contingencies [Line Items]
Estimated Litigation Liability	$ 439		439		$ 100
Redemption of 2019 Notes [Member] | Minimum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies			$ 339
Estimated Litigation Liability					$ 100

Commitments - Undiscounted Gath

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) - Gathering and Processing Equipment [Member] $ in Millions	Sep. 30, 2015USD ($)
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Remainder of Year	$ 461
Gathering, Processing and Transportation Commitment, Due in Second Year	1,927
Gathering, Processing and Transportation Commitment, Due in Third Year	1,939
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,741
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,452
Gathering, Processing and Transportation Commitment, Due after Fifth Year	6,828
Gathering, Processing and Transportation Commitment	$ 14,348

Commitments - Narrative (Detail

Commitments - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)Crew	Sep. 30, 2014USD ($)	Dec. 31, 2014USD ($)	Jul. 20, 2011USD ($)
Long-term Purchase Commitment [Line Items]
Gathering Fee Escalation Rate	15.00%		15.00%
Provision for legal contingencies	$ 0	$ 100	$ 359	$ 100
Investments	225		225		$ 265
Sundrop Fuels Inc [Member]
Long-term Purchase Commitment [Line Items]
Investments	155		155			$ 155
Marketable Securities, Equity Securities	25		25
Drilling Rig Leases [Member]
Long-term Purchase Commitment [Line Items]
Contractual Obligation	321		$ 321
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	265		$ 265
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year One of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew			7
Year of Service Agreement			1 year
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year Two of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew			5
Year of Service Agreement			2 years
Pressure Pumping Leases [Member] | Seven Seven Energy Inc. [Member] | Pressure Pumping Crew Year Three of Agreement [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew			3
Year of Service Agreement			3 years
Net Acreage Shortfall [Member] | Total [Member]
Long-term Purchase Commitment [Line Items]
Provision for legal contingencies	$ 70

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Other Current Liabilities [Line Items]
Accrued Royalties, Current	$ 627	$ 1,176
Accrued Drilling And Production Costs	231	385
Prepayments Received	181	189
Employee-related Liabilities, Current	295	344
Accrual for Taxes Other than Income Taxes, Current	105	55
Dividends Payable, Current	43	101
Other Accrued Liabilities, Current	453	592
Other current liabilities ($11 and $15 attributable to our VIE)	2,374	3,061
Redemption of 2019 Notes [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	439	100
Royalty Settlement [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	$ 0	$ 119

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Other Long-Term Liabilities [Line Items]
Financing obligations	$ 29	$ 30
Unrecognized Tax Benefits	25	45
Other long-term liabilities	135	249
Total other long-term liabilities	387	679
Current liabilities	2,374	3,061
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	198	220
Total other long-term liabilities	218	234
Current liabilities	20	14
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	$ 0	135
Total other long-term liabilities		158
Current liabilities		$ 23

Equity - Common Stock Table (De

Equity - Common Stock Table (Details) - shares	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Shares, Issued Beginning of Period	664,944,232	666,192,000
Restricted stock issuances (net of forfeitures and cancellations)	85,000	(2,413,000)
Stock option exercises	14,000	1,267,000
Common Stock, Shares, Issued End of Period	665,042,789	665,046,000

Equity - Convertible Preferred

Equity - Convertible Preferred Stock Table (Details) - shares	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares outstanding, beginning of period	7,251,515
Shares outstanding, end of period	7,251,515	7,251,515
5.75% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares outstanding, beginning of period	1,497,000	1,497,000	1,497,000
Shares outstanding, end of period	1,497,000	1,497,000	1,497,000
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares outstanding, beginning of period	1,100,000	1,100,000	1,100,000
Shares outstanding, end of period	1,100,000	1,100,000	1,100,000
4.50% Cumulative Convertible Preferred Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares outstanding, beginning of period	2,559,000	2,559,000	2,559,000
Shares outstanding, end of period	2,559,000	2,559,000	2,559,000
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Shares outstanding, beginning of period	2,096,000	2,096,000	2,096,000
Shares outstanding, end of period	2,096,000	2,096,000	2,096,000

Equity - AOCI Changes Net of Ta

Equity - AOCI Changes Net of Tax Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start			$ (143)
Net Other Comprehensive Income	$ 12	$ 3	24	$ 11
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(119)		(119)
Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start			(143)	(167)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			6	3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			18	13
Net Other Comprehensive Income			24	16
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(119)	(151)	(119)	(151)
Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start			0	5
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			0	(5)
Net Other Comprehensive Income			0	(5)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	0	0	0	0
AOCI Including Portion Attributable to Noncontrolling Interest [Member]
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start			(143)	(162)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax			6	3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			18	8
Net Other Comprehensive Income			24	11
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (119)	$ (151)	$ (119)	$ (151)

Equity - AOCI Reclassifications

Equity - AOCI Reclassifications Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL Reclassifications from AOCI	$ 880	$ 2,341	$ 2,693	$ 5,812
Net gain (loss) on Sales of Investments Reclassifications from AOCI	0	0	0	67
Total Reclassification from AOCI	(4,639)	692	(12,450)	1,387
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total Reclassification from AOCI	5	3	18	8
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Investment Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on Sales of Investments Reclassifications from AOCI				(5)
Commodity Contract [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL Reclassifications from AOCI	$ 5	$ 3	$ 18	$ 13

Equity - Narrative (Details)

Equity - Narrative (Details)	9 Months Ended
	Sep. 30, 2015
5.0% Cumulative Convertible Preferred Stock Series 2005 B [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.00%
4.50% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	4.50%
5.75% Cumulative Convertible Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Dividend Rate, Percentage	5.75%

Equity - Noncontrolling Interes

Equity - Noncontrolling Interests Narrative (Details) $ / shares in Units, $ in Millions	1 Months Ended			2 Months Ended	3 Months Ended			9 Months Ended		12 Months Ended
	Jul. 31, 2014USD ($)$ / shares	Mar. 30, 2012USD ($)awell	Oct. 31, 2011aCounty	Dec. 31, 2011USD ($)wellshares	Sep. 30, 2015USD ($)wella$ / sharesshares	Sep. 30, 2014USD ($)shares	Dec. 31, 2011USD ($)shares	Sep. 30, 2015USD ($)awellQuarter$ / sharesshares	Sep. 30, 2014USD ($)shares	Dec. 31, 2012	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013shares	Mar. 31, 2012shares	Nov. 30, 2011$ / sharesshares
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments								$ 8	$ 14
Stockholders' Equity Attributable to Noncontrolling Interest					$ 264			264			$ 1,302
Net income (loss) attributable to noncontrolling interests					13	$ 30		50	110
Repurchase of preferred shares of CHK Utica					$ 0	$ (447)		$ 0	$ (447)
Common Stock, Shares, Issued | shares					665,042,789	665,046,000		665,042,789	665,046,000		664,944,232	666,192,000
Common stock, par value (usd per share) | $ / shares					$ 0.01			$ 0.01			$ 0.01
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a		245,000
Payments for (Proceeds from) Investments		$ 1,250
Preferred Stock, Shares Issued | shares													1,250,000
Overriding Royalty Interest Percentage													3.75%
Stockholders' Equity Attributable to Noncontrolling Interest											$ 1,015
Net income (loss) attributable to noncontrolling interests					$ 13	$ 19		$ 50	$ 56
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well								300
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Future Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well		1,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Drilled Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well								190
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a			700,000
Payments for (Proceeds from) Investments				$ 1,250
Preferred Stock, Shares Issued | shares				1,250,000			1,250,000
Net income (loss) attributable to noncontrolling interests						6			43
Number Of Counties Present In Leasehold Land | County			13
Payments for Repurchase of Preferred Stock and Preference Stock	$ 1,254
Preferred Stock, Redemption Price Per Share | $ / shares	$ 1,189
Repurchase of preferred shares of CHK Utica								$ (447)
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ORRI [Member]
Noncontrolling Interest [Line Items]
Overriding Royalty Interest Percentage				3.00%	3.00%		3.00%	3.00%
Number of Wells, Net | well				1,500				1,500
Percentage of increase in leasehold in which commitment to drill is not met								4.00%		4.00%
Spacing for Wells Drilled | a					150			150
Number of Wells Drilled, Net | well					482			482
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Minimum [Member] | ORRI [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well								1,300
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a								29,000
Stockholders' Equity Attributable to Noncontrolling Interest					$ 264			$ 264			$ 287
Net income (loss) attributable to noncontrolling interests					$ 1	$ 6		$ 0	$ 14
Common stock, par value (usd per share) | $ / shares														$ 19
Common Stock, Shares, Outstanding | shares					46,750,000			46,750,000
Percentage Of Beneficial Interest Owned								51.00%
Number of producing wells | well					69			69
Number of development wells drilled | well								103
Number Of Gross Acres | a								45,400
Maximum amount recoverable by trust under lien							$ 263	$ 33
Quarters of Paid Distributions | Quarter								13
Percentage of incentive distributions received								50.00%
Percentage of remaining cash available for distribution in excess of the incentive threshold								50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust								50.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Maximum [Member]
Noncontrolling Interest [Line Items]
Percentage Of Proceeds From Royalty Interest Conveyed To Trust								90.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Wells, Initial Number of Wells [Member]
Noncontrolling Interest [Line Items]
Number of development wells drilled | well								118
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Common Unit [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Issued | shares														23,000,000
Common Stock, Shares, Outstanding | shares					12,062,500			12,062,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Common Stock, Shares, Outstanding | shares					11,687,500			11,687,500

Equity - Noncontrolling Inter66

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

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock Table (Details) - Restricted Stock [Member] shares in Thousands	9 Months Ended
	Sep. 30, 2015$ / 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	10,091
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	7,016
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(4,025)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(899)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	12,183
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	$ 21.20
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value | $ / shares	13.97
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ / shares	21.78
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price | $ / shares	17.21
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End | $ / shares	$ 17.14

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation Table (Details) - Employee Stock Option [Member]	9 Months Ended
	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	4 years 6 months
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	39.91%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.33%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.91%

Share-Based Compensation - Stoc

Share-Based Compensation - Stock Option Activity Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period Start			4,599
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Gross			1,208
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period			(14)	(1,267)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period			(213)
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End		4,599	5,580
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number			2,248
Share-based Compensation Arrangement by Share-based Payment Award, Options, Additional Disclosures [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start			$ 19.55
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Exercise Price			18.37
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price			18.13
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price			18.54
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price			0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End		$ 19.55	19.33
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price			$ 19.50
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	5 years 10 months	7 years 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4 years 10 months 9 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start			$ 5
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		$ 5	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value			$ 0

Share-Based Compensation - Eq70

Share-Based Compensation - Equity-Classified Compensation Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 16	$ 25	$ 68	$ 81
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	9	12	33	36
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	3	6	18	22
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	4	5	14	13
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	3	5
Other Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 0	$ 0	$ 5

Share-Based Compensation - Liab

Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Shares [Member]	9 Months Ended
	Sep. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	46.36%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.71%
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	Sep. 30, 2015	Jan. 01, 2015	Jan. 01, 2014	Jan. 01, 2013
Payable 2016 [Member] | Year of 2013 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,701,941
Fair Value of Share Based Award	$ 9			$ 35
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 9
Payable 2017 [Member] | Year of 2014 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	609,637
Fair Value of Share Based Award	$ 1		$ 16
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 1
Payable 2018 [Member] | Year of 2015 [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	696,683
Fair Value of Share Based Award	$ 4	$ 13
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 2

Share-Based Compensation - Li73

Share-Based Compensation - Liability-Classified Compensation Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 16	$ 25	$ 68	$ 81
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	9	12	33	36
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	2	3	5
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	3	6	18	22
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(3)	(30)	(34)	(10)
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)	(12)	(16)	(2)
Performance Shares [Member] | Restructuring Charges [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(1)	(17)	(16)	(11)
Performance Shares [Member] | Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	0	(1)	(1)	0
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	$ 0	$ (1)	$ 3

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value	$ 59,000,000		$ 59,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	149,000,000		$ 149,000,000
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition			2 years 15 days
Restricted Stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition			1 year 9 months 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	10,000,000		$ 10,000,000
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 2014 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage				100.00%
Management [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			33.00%
Management [Member] | Employee Stock Option [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period			7 years
Management [Member] | Employee Stock Option [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period			10 years
Management [Member] | Stock Option Award Three Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			3 years
Management [Member] | Stock Optioin Award Four Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			4 years
Management [Member] | Stock option Award Five Year Anniversary [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period			5 years
Management [Member] | Years of 2013 and 2014 [Member] | Share-Based Comp Award Three Year Anniversary [Member] | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights				third
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			200.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			0.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			125.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			0.00%
Management [Member] | Year of 2013 [Member] | Long-Term Incentive Plan [Member] | Operational Component [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			62.50%
Management [Member] | Year of 2014 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			0.00%
Management [Member] | Year of 2014 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			200.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | Performance Shares [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			200.00%
Management [Member] | Year of 2015 [Member] | Long-Term Incentive Plan [Member] | TSR [Member] | 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%
Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Decrease in tax benefit from stock-based compensation			$ (11,000,000)	$ (1,000,000)
Paid-In Capital [Member] | Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Decrease in tax benefit from stock-based compensation	5,000,000	$ 4,000,000	11,000,000	1,000,000
Paid-In Capital [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Decrease in tax benefit from stock-based compensation	$ 0	$ 0		$ 0
Decrease in tax benefit from stock-based compensation			$ 0

Derivative and Hedging Activi75

Derivative and Hedging Activities - Derivative Instruments Table (Details) MMBbls in Millions, $ in Millions, MMBTU in Trillions	Dec. 31, 2014USD ($)MMBTUMMBbls	Sep. 30, 2015USD ($)MMBTUMMBbls
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 652	$ 469
Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	52.7	28.8
Derivative Assets (Liabilities), at Fair Value, Net	$ 422	$ 163
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	12.5	8
Derivative Assets (Liabilities), at Fair Value, Net	$ 471	$ 161
Crude Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	4.4	1.1
Derivative Assets (Liabilities), at Fair Value, Net	$ 40	$ 11
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	35.8	18.1
Derivative Assets (Liabilities), at Fair Value, Net	$ (89)	$ (9)
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	0	1.6
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0
Natural Gas [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 299	$ 91
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	735	599
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 281	$ 174
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	275	295
Natural Gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 165	$ 28
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	207	36
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (170)	$ (107)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	193	193
Natural Gas [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 23	$ (4)
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	60	75
Commodity Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 721	$ 254

Derivative and Hedging Activi76

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 469	$ 652
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	469	652
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	254	721
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	254	722
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	254	722
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(17)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(17)
Not Designated as Hedging Instrument [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	291
Derivative Liability, Fair Value, Gross Asset	0
Derivative, Fair Value, Net	291
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	370	974
Derivative Asset, Fair Value, Gross Liability	(71)	(95)
Derivative, Fair Value, Net	299	879
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	43
Derivative Asset, Fair Value, Gross Liability	0
Derivative, Fair Value, Net	43
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	12	16
Derivative Asset, Fair Value, Gross Liability	(3)	(10)
Derivative, Fair Value, Net	9	6
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	248
Derivative Asset, Fair Value, Gross Liability	0
Derivative, Fair Value, Net	248
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(95)	(105)
Derivative Liability, Fair Value, Gross Asset	71	95
Derivative, Fair Value, Net	(24)	(10)
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(5)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(5)
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(33)	(163)
Derivative Liability, Fair Value, Gross Asset	3	10
Derivative, Fair Value, Net	(30)	(153)
Not Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability		(12)
Derivative Liability, Fair Value, Gross Asset		0
Derivative, Fair Value, Net		(12)
Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(76)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	(76)	(53)
Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member] | Foreign Exchange Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(76)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	$ (76)	$ (53)

Derivative and Hedging Activi77

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	$ 0	$ (2)	$ 10	$ 48
Total oil, natural gas and NGL revenues	880	2,341	2,693	5,812
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL revenues	653	1,777	2,353	5,842
Gains (losses) on undesignated oil and natural gas derivatives	234	569	369	(5)
Losses on terminated cash flow hedges	$ (7)	$ (5)	$ (29)	$ (25)

Derivative and Hedging Activi78

Derivative and Hedging Activities Derivative and Hedging Activities, Marketing, Gathering and Compression Sales (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Marketing, Gathering and Compression Revenue	$ 2,013	$ 3,362	$ 5,993	$ 9,543
Marketing, Gathering And Compression [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Refining and Marketing Revenue	1,943	3,362	5,703	9,543
Marketing, Gathering And Compression [Member] | Other Contracts, B [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	41		77
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings			281	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements			9	0
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contract [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	$ 70	$ 0	$ 290	$ 0

Derivative and Hedging Activi79

Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$ 171	$ 170	$ 513	$ 534
Interest expense on term loan	0	0	0	36
Amortization of loan discount, issuance costs and other	14	9	37	44
Interest expense on credit facilities	2	6	8	22
Gains on terminated fair value hedges	0	0	(2)	(2)
(Gains) losses on undesignated interest rate derivatives	0	2	(10)	(48)
Capitalized interest	(99)	(170)	(336)	(504)
Total interest expense	$ 88	$ 17	$ 210	$ 82

Derivative and Hedging Activi80

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start			$ (143)
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $5, $0, $4 and $3	$ 7	$ 0	6	$ 3
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $2, $11 and $12	5	3	18	13
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(119)		(119)
Cash Flow Hedging [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(211)	(243)	(231)	(269)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(131)	(154)	(143)	(167)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	12	0	10	6
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $5, $0, $4 and $3			6	3
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	7	5	29	25
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $2, $11 and $12	5	3	18	13
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(192)	(238)	(192)	(238)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (119)	$ (151)	$ (119)	$ (151)

Derivative and Hedging Activi81

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 469	$ 652
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	382	989
Derivative Liability	(128)	(268)
Derivative Assets (Liabilities), at Fair Value, Net	254	721
Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	(17)
Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	(76)	(53)
Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	291	1
Fair Value, Inputs, Level 1 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	255	705
Fair Value, Inputs, Level 2 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	343	784
Derivative Liability	(12)	(9)
Fair Value, Inputs, Level 2 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	(17)
Fair Value, Inputs, Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	(76)	(53)
Fair Value, Inputs, Level 2 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	214	(53)
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	39	205
Derivative Liability	(116)	(259)
Derivative Assets (Liabilities), at Fair Value, Net	(77)	(54)	$ (305)	$ (478)
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Liability	0	0
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	291	1
Derivative Assets (Liabilities), at Fair Value, Net	$ 291	$ 1	$ 0	$ 0

Derivative and Hedging Activi82

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	$ 652
Derivative Assets (Liabilities), at Fair Value, Net, Period End	469
Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	721
Derivative Assets (Liabilities), at Fair Value, Net, Period End	254
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	(53)
Derivative Assets (Liabilities), at Fair Value, Net, Period End	214
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	(54)	$ (478)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	99	53
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	(122)	124
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Transfers, Net		(4)
Derivative Assets (Liabilities), at Fair Value, Net, Period End	(77)	(305)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	72	60
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Derivative Assets (Liabilities), at Fair Value, Net, Period Start	1	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	281	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	9	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	291	0
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	$ 281	$ 0

Derivative and Hedging Activi83

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Energy Related Derivative, Oil Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	31.70%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 2
Energy Related Derivative, Oil Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	23.69%
Energy Related Derivative, Oil Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	37.51%
Other Contract [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	23.82%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 291
Other Contract [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	20.22%
Other Contract [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	44.86%
Energy Related Derivative, Natural Gas Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	31.31%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (79)
Energy Related Derivative, Natural Gas Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	19.76%
Energy Related Derivative, Natural Gas Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	61.06%

Derivative and Hedging Activi84

Derivative and Hedging Activities - Narrative (Details) € in Millions, MMBoe in Millions, $ in Millions, MMBTU in Billions	1 Months Ended	3 Months Ended	9 Months Ended
	Dec. 31, 2006USD ($)$ / €	Sep. 30, 2015USD ($)MMBoeMMBTUcounterpartyDerivatives$ / €	Sep. 30, 2015USD ($)MMBoecounterpartyDerivatives$ / €	Sep. 30, 2015EUR (€)MMBoecounterpartyDerivatives$ / €	Jun. 30, 2015USD ($)	Apr. 30, 2015USD ($)	Dec. 31, 2014USD ($)$ / €	Sep. 30, 2014USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2006EUR (€)$ / €
Derivative [Line Items]
Number of Interest Rate Derivatives Held | Derivatives		0	0	0
Derivative Assets (Liabilities), at Fair Value, Net		$ 469	$ 469				$ 652
Accumulated other comprehensive loss		119	119				143
Expected amount to be transferred of during the next 12 months		20	20
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Euro-denominated debt in notes payable, adjusted value	$ 344	$ 384	$ 384				416
Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty		9	9	9
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier		1.30	1.30	1.30
Borrowing capacity		$ 7,100	$ 7,100
Multi-Counterparty Hedging Facility [Member] | Minimum [Member]
Derivative [Line Items]
Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier		1.65	1.65	1.65
Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Borrowing capacity						$ 16,500
Line of Credit Facility, Current Borrowing Capacity		$ 7,100	$ 7,100
Cash Flow Hedging [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		119	119		$ 131		143	$ 151	$ 154	$ 167
Cash Flow Hedging [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		118	$ 118
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, Amount of Hedged Item							850
Amortization Period of Deferred Gain (Loss) on Discontinuation of Fair Value Hedge			6 years
Deferred (Gain) Loss on Discontinuation of Fair Value Hedge		8	$ 8
Euro-denominated debt in notes payable, adjusted value		$ 8	$ 8				10
Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net							(17)
Derivative Liability, Fair Value, Gross Liability							$ (17)
Cross Currency Interest Rate Contract [Member] | 6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member]
Derivative [Line Items]
Derivative, Forward Exchange Rate | $ / €	1.3325	1.1177	1.1177	1.1177			1.2098				1.3325
Semi Annual Interest Rate Swap Payments By Counterparty | €				€ 344							€ 11
Dollar Equivalent Interest Rate	7.491%
Short-term Debt, Refinanced, Description	$ 17	$ 459	$ 459
Foreign Exchange Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(76)	(76)				$ (53)
Derivative Liability, Fair Value, Gross Liability		$ (76)	$ (76)				(53)
Other Contracts, A [Member]
Derivative [Line Items]
Derivative, Number of Instruments Held | Derivatives		1	1	1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements		$ 36	$ 63
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		17	17	17
Energy Related Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe) | MMBoe		444	444	444
Price Risk Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		27.3	27.3	27.3
Price Risk Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		87.2	87.2	87.2
Basis Derivative [Member] | Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe) | MMBoe		444	444	444
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		1.2	1.2	1.2
Basis Derivative [Member] | Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		12.9	12.9	12.9
Fair Value, Inputs, Level 3 [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		$ 214	$ 214				$ (53)
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contracts, A [Member]
Derivative [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		$ 70	$ 291

Oil and Natural Gas Property 85

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

Oil and Natural Gas Property 86

Oil and Natural Gas Property Transactions - VPP Volumes Produced During Period Table (Details) Mcfe in Millions, Mcf in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015McfeMBblsMcf	Sep. 30, 2014McfeMBblsMcf	Sep. 30, 2015McfeMBblsMcf	Sep. 30, 2014McfeMBblsMcf
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	25	35.4	86.6	112
Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	127,900	166,200	396,700	523,600
Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	22.4	32	77.9	101.2
Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	346,200	416,000	1,083,100	1,301,500
VPP 10 Anadarko Basin Granite Wash [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4	5	12.7	15.8
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	76,000	98,000	237,000	310,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	2.1	2.6	6.5	8.1
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	253,300	314,500	798,300	989,600
VPP 9 Mid-Continent [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4.3	4.7	13.2	14.4
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	41,400	46,100	127,500	142,600
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	3.6	3.8	10.8	11.7
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	92,900	101,500	284,800	311,900
VPP 8 Barnett Shale [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	8.9	14.8	36.5	45.7
VPP 8 Barnett Shale [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	8.9	14.8	36.5	45.7
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 6 East Texas and Texas Gulf Coast [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	0	1.1	0	3.4
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	6,000	0	18,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	0	1.1	0	3.3
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 5 South Texas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	0	1.2	0	4.7
VPP 5 South Texas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	4,200	0	16,500
VPP 5 South Texas [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	0	1.2	0	4.6
VPP 5 South Texas [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	2	2.3	6.2	7
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	10,500	11,900	32,200	36,500
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	2	2.2	6.1	6.8
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 3 Anadarko Basin [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	1.6	1.8	4.9	5.5
VPP 3 Anadarko Basin [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	1.6	1.8	4.9	5.5
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	1	1.1	3.1	5.1
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	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	1	1.1	3.1	5.1
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	0	0
VPP 1 Kentucky and West Virginia [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	3.2	3.4	10	10.4
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	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	3.2	3.4	10	10.4
VPP 1 Kentucky and West Virginia [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	0	0

Oil and Natural Gas Property 87

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	9 Months Ended
	Sep. 30, 2015McfeMBblsMcfMMBbls	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	259
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)	1.8
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	214.8
Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls	14
Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	5.6
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	77 months
Proved Developed Reserves (Energy) | Mcfe	61.3
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	1.1
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	31.5
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)	3.9
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)	65 months
Proved Developed Reserves (Energy) | Mcfe	76.6
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls		1.7
VPP 9 Mid-Continent [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0.7
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf		138
VPP 9 Mid-Continent [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	62.5
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)	1.7
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)	15 months
Proved Developed Reserves (Energy) | Mcfe	9.6
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	9.3
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls			0
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 3 Anadarko Basin [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe				93
VPP 3 Anadarko Basin [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	46 months
Proved Developed Reserves (Energy) | Mcfe	19.1
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	19.1
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)	43 months
Proved Developed Reserves (Energy) | Mcfe	10.8
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls					0
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf					94
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	10.8
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls					0
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 1 Kentucky and West Virginia [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe						208
VPP 1 Kentucky and West Virginia [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	87 months
Proved Developed Reserves (Energy) | Mcfe	81.6
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	81.6
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 88

Oil and Natural Gas Property Transactions - Narrative (Details)	1 Months Ended	3 Months Ended		9 Months Ended		60 Months Ended
	Mar. 30, 2012a	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)awellCompressor	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Jun. 30, 2013Resource_PlaysJoint_Venture
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				$ 188,000,000	$ 723,000,000
RKI Exploration & Production, LLC [Member]
Business Acquisition [Line Items]
Number Of Gross Acres | a			440,000
RKI Exploration & Production, LLC [Member] | Chesapeake Obligation [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			$ 450,000,000
Number Of Net Acres | a			137,000
Number of Wells, Gross | well			67
Interest Sold			22.00%
RKI Exploration & Production, LLC [Member] | RKI Obligation [Member]
Business Acquisition [Line Items]
Number Of Net Acres | a			203,000
Number of Wells, Gross | well			186
Interest Sold			48.00%
Rice Drilling [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			$ 233,000,000
Hilcorp Energy [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties			$ 133,000,000
Equipment, Number of Units | Compressor			61
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties				52,000,000	335,000,000
Number of Joint Ventures | Joint_Venture						8
Number of Resource Plays | Resource_Plays						8
Proceeds from Divestiture of Interest in Joint Venture				8,000,000,000
Total Drilling Carries				9,000,000,000
Oil And Gas Benefit From Drilling Carries				51,000,000	535,000,000
Corporate Joint Venture [Member] | Minimum [Member]
Business Acquisition [Line Items]
Interest Sold						20.00%
Corporate Joint Venture [Member] | Maximum [Member]
Business Acquisition [Line Items]
Interest Sold						50.00%
JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]
Business Acquisition [Line Items]
Proceeds from Divestiture of Interest in Joint Venture				30,000,000	$ 24,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets				$ 0
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		$ 90,000,000
Number Of Net Acres | a	245,000

Investments - Schedule of Inves

Investments - Schedule of Investments Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Carrying Value of Investments	$ 225	$ 265
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Carrying Value of Investments	$ 88	$ 116
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	56.00%	56.00%
Carrying Value of Investments	$ 119	$ 130
Other Investment Companies [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	0.00%	0.00%
Carrying Value of Investments	$ 18	$ 19

Investments - Narrative (Detail

Investments - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments	$ 0	$ 239
FTS International, Inc. [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	72
Equity method accretion adjustments	44
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	18
Interest Costs Capitalized	7
Excess carrying value of investment over underlying equity in net assets	$ 85
Chaparral Energy Inc [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments		209
Equity Method Investment, Realized Gain (Loss) on Disposal		73
Other Investments [Member]
Schedule of Equity Method Investments [Line Items]
Proceeds from sales of investments		30
Equity Method Investment, Realized Gain (Loss) on Disposal		$ 6

Variable Interest Entities - Na

Variable Interest Entities - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 1,759	$ 4,108	$ 90	$ 837
Proved natural gas and oil properties	62,941	58,594
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	56,196	39,043
Current liabilities	2,374	3,061
Non-Guarantor Subsidiaries [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	1	84	$ 90	$ 38
Current liabilities	13	68
Variable Interest Entities, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	1	1
Proved natural gas and oil properties	488	488
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	397	251
Current liabilities	$ 11	$ 15
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	10.00%
Variable interest entity, carrying value of investment	$ 10
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Minimum [Member]
Variable Interest Entity [Line Items]
Royalty percentage minimum	7.00%
Royalty percentage maximum	7.00%
Variable Interest Entities, Primary Beneficiary [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 25
Royalty percentage minimum	22.50%
Royalty percentage maximum	22.50%
Majority-Owned Subsidiary, Unconsolidated [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member]
Variable Interest Entity [Line Items]
Percentage of acquisition	90.00%
Majority-Owned Subsidiary, Unconsolidated [Member] | Non-Guarantor Subsidiaries [Member] | Limited Partner [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 225

Other Property and Equipment Ne

Other Property and Equipment Net Gains (Losses) on Sales of Fixed Assets Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ (1)	$ (86)	$ 3	$ (201)
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	(1)	(75)	(1)	(195)
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	1	(5)	1	8
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	0	0	(7)
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	(1)	(6)	0	(5)
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 0	$ 0	$ 3	$ (2)

Other Property and Equipment -

Other Property and Equipment - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)Compressor	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)Compressor	Dec. 31, 2014USD ($)
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ (1)	$ (86)	$ 3	$ (201)
Property and equipment held for sale, net	94		94		$ 93
Hilcorp Energy [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units | Compressor		61
Exterran Partners L.P. [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Sale of Property, Plant, and Equipment		$ 133
Compressor [Member] | Hilcorp Energy [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units | Compressor		61
Proceeds from Sale of Property, Plant, and Equipment		$ 19
Net (gains) losses on sales of fixed assets		$ (6)
Compressor [Member] | Exterran Partners L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units | Compressor		162		499
Proceeds from Sale of Property, Plant, and Equipment				$ 495
Net (gains) losses on sales of fixed assets		$ (68)		$ (161)
Compressor [Member] | Access Midstream Partners, L.P. [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units | Compressor				102
Proceeds from Sale of Property, Plant, and Equipment				$ 159
Net (gains) losses on sales of fixed assets				(24)
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	(1)	$ (6)	0	$ (5)
Land and Building [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]
Property, Plant and Equipment [Line Items]
Property and equipment held for sale, net	$ 94		$ 94		$ 93

Impairments - Narrative (Detail

Impairments - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)Compressor	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)Rigs
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of Leasehold	$ 1,000
Impairment of oil and natural gas properties	5,416	$ 0	$ 15,407	$ 0
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	184		184
Impairments of fixed assets and other	79	15	167	75
Gain (Loss) on Contract Termination			(7)
Provision for legal contingencies	0	100	359	100
Contractual Dispute [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	47
Note Receivable [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	9		22
Net Acreage Shortfall [Member] | Total [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Provision for legal contingencies	70
Other Cost and Expense, Operating		$ 22
Natural Gas Compressors [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other	$ 21
Equipment, Number of Units | Compressor	466
Proceeds from Sale of Property, Plant, and Equipment			$ 63
Drilling Rigs [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
Impairments of fixed assets and other				15
Gain (Loss) on Contract Termination				$ (8)
Leased Equipment Purchased | Rigs				31
Payments to Acquire Property, Plant, and Equipment				$ 140

Restructuring Restructuring - N

Restructuring Restructuring - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Restructuring Cost and Reserve [Line Items]
Restructuring, Percentage of Employees Effected	15.00%
Restructuring and other termination costs	$ 53	$ (14)	$ 39	$ 12
Allocated Share-based Compensation Expense	16	25	68	81
Performance Shares [Member]
Restructuring Cost and Reserve [Line Items]
Allocated Share-based Compensation Expense	(3)	(30)	(34)	(10)
Restructuring Charges [Member] | Performance Shares [Member]
Restructuring Cost and Reserve [Line Items]
Allocated Share-based Compensation Expense	(1)	$ (17)	$ (16)	(11)
One-time Termination Benefits [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs	$ 55
Spinoff [Member] | Seven Seven Energy Inc. [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring and other termination costs				$ 15

Spin-Off of Oilfield Services96

Spin-Off of Oilfield Services Business - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stockholders' equity decreased amount					$ (270)
Restructuring and other termination costs		$ 53	$ (14)	$ 39	12
Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stockholders' Equity Note, Stock Split	one share of SSE common stock and cash in lieu of fractional shares for every 14 shares of Chesapeake common stock
Seven Seven Energy Inc. [Member] | Spinoff [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Deferred Tax Liabilities, Deferred Expense			152		152
Restructuring and other termination costs					15
Seven Seven Energy Inc. [Member] | Secured Debt [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross			400		400
Seven Seven Energy Inc. [Member] | Senior Notes [Member] | 6.5% Senior Notes Due 2022 [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross			$ 500		$ 500
Debt Instrument, Interest Rate, Stated Percentage			6.50%		6.50%
General Partner Distributions	$ 391
Seven Seven Energy Inc. [Member] | Seven Seven Energy Inc. Revolving Credit Facility [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity			$ 275		$ 275

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
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	58	57
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(60)	(58)
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	58	57
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(60)	(58)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	$ 0	$ 0

Segment Information - Table (De

Segment Information - Table (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total Revenues	$ 2,893,000,000	$ 5,703,000,000	$ 8,686,000,000	$ 15,901,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(5,576,000,000)	1,129,000,000	(16,264,000,000)	2,246,000,000
TOTAL ASSETS	21,286,000,000		21,286,000,000		$ 40,751,000,000
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	880,000,000	2,341,000,000	2,693,000,000	5,812,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(5,625,000,000)	987,000,000
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	2,013,000,000	3,362,000,000	5,993,000,000	9,543,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	70,000,000	113,000,000
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	516,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	0	0
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	30,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	(37,000,000)	(63,000,000)
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	2,893,000,000	5,703,000,000	8,686,000,000	15,901,000,000
Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	853,000,000	2,341,000,000	2,614,000,000	5,812,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest			(16,759,000,000)	2,089,000,000
TOTAL ASSETS	15,646,000,000		15,646,000,000		35,381,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	3,059,000,000	5,512,000,000	9,476,000,000	16,289,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest			208,000,000	325,000,000
TOTAL ASSETS	1,711,000,000		1,711,000,000		1,978,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	1,060,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest			0	(16,000,000)
TOTAL ASSETS	0		0		0
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	30,000,000
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest			(82,000,000)	(24,000,000)
TOTAL ASSETS	4,342,000,000		4,342,000,000		4,283,000,000
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest	16,000,000	92,000,000	369,000,000	(128,000,000)
Intersegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	27,000,000	0	79,000,000	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,046,000,000)	(2,150,000,000)	(3,483,000,000)	(6,746,000,000)
Intersegment Eliminations [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	(544,000,000)
Intersegment Eliminations [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
Intersegment Eliminations [Member] | Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,019,000,000)	(2,150,000,000)	(3,404,000,000)	(7,290,000,000)
TOTAL ASSETS	(413,000,000)		(413,000,000)		$ (891,000,000)
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 1,019,000,000	$ 2,150,000,000	$ 3,404,000,000	$ 7,290,000,000

Segment Information - Narrative

Segment Information - Narrative (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)Segment	Sep. 30, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			2
Total Revenues	$ 2,893,000,000	$ 5,703,000,000	$ 8,686,000,000	$ 15,901,000,000
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	2,013,000,000	3,362,000,000	5,993,000,000	9,543,000,000
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,046,000,000)	(2,150,000,000)	(3,483,000,000)	(6,746,000,000)
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	516,000,000
Oilfield Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ 0	$ 0	$ (544,000,000)

Condensed Consolidating Fina100

Condensed Consolidating Financial Information - Balance Sheet Table (Details) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 1,759	$ 4,108	$ 90	$ 837
Restricted cash	0	38
Other current assets	203	207
Intercompany receivable, net	0	0
Total Current Assets	3,579	7,468
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	14,726	30,143
Other property and equipment, net	2,139	2,279
Property and equipment held for sale, net	94	93
Total Property and Equipment, Net	16,959	32,515
LONG-TERM ASSETS:
Other long-term assets	266	497
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	21,286	40,751
CURRENT LIABILITIES:
Current liabilities	2,374	3,061
Intercompany payable, net	0	0
Total Current Liabilities	4,557	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	10,674	11,154
Deferred income tax liabilities	574	4,185
Other long-term liabilities	387	679
Total Long-Term Liabilities	12,183	16,683
EQUITY:
Chesapeake stockholders’ equity	4,282	16,903
Noncontrolling interests	264	1,302
Total Equity	4,546	18,205	17,631
TOTAL LIABILITIES AND EQUITY	21,286	40,751
Parent Company Member]
CURRENT ASSETS:
Cash and cash equivalents	1,849	4,100	11	799
Restricted cash	0	0
Other current assets	69	55
Intercompany receivable, net	24,909	24,527
Total Current Assets	26,827	28,682
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	0	0
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	0	0
LONG-TERM ASSETS:
Other long-term assets	112	153
Investments in subsidiaries and intercompany advances	(10,358)	126
TOTAL ASSETS	16,581	28,961
CURRENT LIABILITIES:
Current liabilities	1,529	792
Intercompany payable, net	0	0
Total Current Liabilities	1,529	792
LONG-TERM LIABILITIES:
Long-term debt, net	10,674	11,154
Deferred income tax liabilities	(5)	0
Other long-term liabilities	101	112
Total Long-Term Liabilities	10,770	11,266
EQUITY:
Chesapeake stockholders’ equity	4,282	16,903
Noncontrolling interests	0	0
Total Equity	4,282	16,903
TOTAL LIABILITIES AND EQUITY	16,581	28,961
Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	12	2	0	0
Restricted cash	0	0
Other current assets	1,736	3,174
Intercompany receivable, net	0	0
Total Current Assets	1,748	3,176
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	13,503	28,358
Other property and equipment, net	2,139	2,276
Property and equipment held for sale, net	94	93
Total Property and Equipment, Net	15,736	30,727
LONG-TERM ASSETS:
Other long-term assets	626	618
Investments in subsidiaries and intercompany advances	788	467
TOTAL ASSETS	18,898	34,988
CURRENT LIABILITIES:
Current liabilities	3,118	5,081
Intercompany payable, net	24,788	24,940
Total Current Liabilities	27,906	30,021
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	516	3,751
Other long-term liabilities	834	1,090
Total Long-Term Liabilities	1,350	4,841
EQUITY:
Chesapeake stockholders’ equity	(10,358)	126
Noncontrolling interests	0	0
Total Equity	(10,358)	126
TOTAL LIABILITIES AND EQUITY	18,898	34,988
Non-Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	1	84	90	38
Restricted cash	0	38
Other current assets	15	93
Intercompany receivable, net	457	341
Total Current Assets	473	556
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	98	1,112
Other property and equipment, net	0	3
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	98	1,115
LONG-TERM ASSETS:
Other long-term assets	10	26
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	581	1,697
CURRENT LIABILITIES:
Current liabilities	13	68
Intercompany payable, net	0	0
Total Current Liabilities	13	68
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	32	234
Other long-term liabilities	0	142
Total Long-Term Liabilities	32	376
EQUITY:
Chesapeake stockholders’ equity	536	1,253
Noncontrolling interests	0	0
Total Equity	536	1,253
TOTAL LIABILITIES AND EQUITY	581	1,697
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	(103)	(78)	$ (11)	$ 0
Restricted cash	0	0
Other current assets	0	0
Intercompany receivable, net	(25,366)	(24,868)
Total Current Assets	(25,469)	(24,946)
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	1,125	673
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	1,125	673
LONG-TERM ASSETS:
Other long-term assets	0	(29)
Investments in subsidiaries and intercompany advances	9,570	(593)
TOTAL ASSETS	(14,774)	(24,895)
CURRENT LIABILITIES:
Current liabilities	(103)	(78)
Intercompany payable, net	(24,788)	(24,940)
Total Current Liabilities	(24,891)	(25,018)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	31	200
Other long-term liabilities	0	0
Total Long-Term Liabilities	31	200
EQUITY:
Chesapeake stockholders’ equity	9,822	(1,379)
Noncontrolling interests	264	1,302
Total Equity	10,086	(77)
TOTAL LIABILITIES AND EQUITY	(14,774)	(24,895)
Consolidated Entities [Member]
CURRENT ASSETS:
Other current assets	1,820	3,322
LONG-TERM ASSETS:
Other long-term assets	748	768
CURRENT LIABILITIES:
Current liabilities	4,557	5,863
LONG-TERM LIABILITIES:
Other long-term liabilities	$ 935	$ 1,344

Condensed Consolidating Fina101

Condensed Consolidating Financial Information -Statement Of Operations Table (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
REVENUES:
Oil, natural gas and NGL	$ 880	$ 2,341	$ 2,693	$ 5,812
Marketing, gathering and compression	2,013	3,362	5,993	9,543
Oilfield services	0	0	0	546
Total Revenues	2,893	5,703	8,686	15,901
OPERATING EXPENSES:
Oil, natural gas and NGL production	251	298	826	868
Production taxes	25	62	87	185
Marketing, gathering and compression	1,955	3,369	5,751	9,515
Oilfield services	0	0	0	431
General and administrative	49	60	174	229
Restructuring and other termination costs	53	(14)	39	12
Provision for legal contingencies	0	100	359	100
Oil, natural gas and NGL depreciation, depletion and amortization	488	688	1,773	1,977
Depreciation and amortization of other assets	31	37	100	194
Impairment of oil and natural gas properties	5,416	0	15,407	0
Impairments of fixed assets and other	79	15	167	75
Net gains (losses) on sales of fixed assets	(1)	(86)	3	(201)
Total Operating Expenses	8,346	4,529	24,686	13,385
INCOME FROM OPERATIONS	(5,453)	1,174	(16,000)	2,516
OTHER INCOME (EXPENSE):
Interest expense	(88)	(17)	(210)	(82)
Income (Loss) from Equity Method Investments	(33)	(27)	(57)	(72)
Net gain (loss) on sales of investments	0	0	0	67
Losses on purchases of debt	0	0	0	(195)
Other income (expense)	(2)	(1)	3	12
Proceeds from Equity Method Investment, Dividends or Distributions	0	0	0	0
Total Other Expense	(123)	(45)	(264)	(270)
INCOME (LOSS) BEFORE INCOME TAXES	(5,576)	1,129	(16,264)	2,246
Total Income Tax Expense (Benefit)	(937)	437	(3,814)	859
NET INCOME (LOSS)	(4,639)	692	(12,450)	1,387
Net income attributable to noncontrolling interests	(13)	(30)	(50)	(110)
Net income (loss) attributable to Chesapeake	(4,652)	662	(12,500)	1,277
Other Comprehensive Income (Loss), Net of Tax	12	3	24	11
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4,640)	665	(12,476)	1,288
Parent Company Member]
REVENUES:
Oil, natural gas and NGL	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services				0
Total Revenues	0	0	0	0
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0	0
Production taxes	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services				0
General and administrative	1	0	3	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies		0	339	0
Oil, natural gas and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	0	0	0	0
Impairment of oil and natural gas properties	0	0	0	0
Impairments of fixed assets and other	0	0	0	0
Net gains (losses) on sales of fixed assets	0	0	0	0
Total Operating Expenses	1	0	342	0
INCOME FROM OPERATIONS	(1)	0	(342)	0
OTHER INCOME (EXPENSE):
Interest expense	(182)	(178)	(532)	(524)
Income (Loss) from Equity Method Investments	0	0	0	0
Net gain (loss) on sales of investments				0
Losses on purchases of debt				(195)
Other income (expense)	140	56	100	535
Proceeds from Equity Method Investment, Dividends or Distributions	(4,594)	737	(11,908)	1,391
Total Other Expense	(4,636)	615	(12,340)	1,207
INCOME (LOSS) BEFORE INCOME TAXES	(4,637)	615	(12,682)	1,207
Total Income Tax Expense (Benefit)	15	(47)	(182)	(70)
NET INCOME (LOSS)	(4,652)	662	(12,500)	1,277
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(4,652)	662	(12,500)	1,277
Other Comprehensive Income (Loss), Net of Tax	8	0	6	3
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4,644)	662	(12,494)	1,280
Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	855	2,223	2,583	5,505
Marketing, gathering and compression	2,013	3,361	5,993	9,539
Oilfield services				41
Total Revenues	2,868	5,584	8,576	15,085
OPERATING EXPENSES:
Oil, natural gas and NGL production	245	289	799	837
Production taxes	25	61	85	181
Marketing, gathering and compression	1,955	3,368	5,750	9,512
Oilfield services				53
General and administrative	47	59	168	182
Restructuring and other termination costs	53	(14)	39	9
Provision for legal contingencies		100	20	100
Oil, natural gas and NGL depreciation, depletion and amortization	478	662	1,727	1,910
Depreciation and amortization of other assets	31	37	100	116
Impairment of oil and natural gas properties	5,412	0	15,395	0
Impairments of fixed assets and other	79	15	167	52
Net gains (losses) on sales of fixed assets	(1)	(86)	3	(194)
Total Operating Expenses	8,324	4,491	24,253	12,758
INCOME FROM OPERATIONS	(5,456)	1,093	(15,677)	2,327
OTHER INCOME (EXPENSE):
Interest expense	(58)	(11)	(133)	(14)
Income (Loss) from Equity Method Investments	(33)	(27)	(57)	(69)
Net gain (loss) on sales of investments				67
Losses on purchases of debt				0
Other income (expense)	(113)	119	5	3
Proceeds from Equity Method Investment, Dividends or Distributions	(50)	(58)	(381)	(167)
Total Other Expense	(254)	23	(566)	(180)
INCOME (LOSS) BEFORE INCOME TAXES	(5,710)	1,116	(16,243)	2,147
Total Income Tax Expense (Benefit)	(985)	454	(3,720)	884
NET INCOME (LOSS)	(4,725)	662	(12,523)	1,263
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(4,725)	662	(12,523)	1,263
Other Comprehensive Income (Loss), Net of Tax	4	3	18	8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4,721)	665	(12,505)	1,271
Non-Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	25	118	110	310
Marketing, gathering and compression	0	1	0	4
Oilfield services				983
Total Revenues	25	119	110	1,297
OPERATING EXPENSES:
Oil, natural gas and NGL production	6	9	27	31
Production taxes	0	1	2	4
Marketing, gathering and compression	0	1	1	3
Oilfield services				769
General and administrative	1	1	3	47
Restructuring and other termination costs	0	0	0	3
Provision for legal contingencies		0	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	11	44	66	124
Depreciation and amortization of other assets	0	0	0	142
Impairment of oil and natural gas properties	37	104	443	202
Impairments of fixed assets and other	0	0	0	23
Net gains (losses) on sales of fixed assets	0	0	0	(7)
Total Operating Expenses	55	160	542	1,341
INCOME FROM OPERATIONS	(30)	(41)	(432)	(44)
OTHER INCOME (EXPENSE):
Interest expense	0	0	0	(42)
Income (Loss) from Equity Method Investments	0	0	0	(5)
Net gain (loss) on sales of investments				0
Losses on purchases of debt				0
Other income (expense)	0	(4)	0	(2)
Proceeds from Equity Method Investment, Dividends or Distributions	0	0	0	0
Total Other Expense	0	(4)	0	(49)
INCOME (LOSS) BEFORE INCOME TAXES	(30)	(45)	(432)	(93)
Total Income Tax Expense (Benefit)	7	(17)	(101)	(36)
NET INCOME (LOSS)	(37)	(28)	(331)	(57)
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(37)	(28)	(331)	(57)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(37)	(28)	(331)	(57)
Eliminations [Member]
REVENUES:
Oil, natural gas and NGL	0	0	0	(3)
Marketing, gathering and compression	0	0	0	0
Oilfield services				(478)
Total Revenues	0	0	0	(481)
OPERATING EXPENSES:
Oil, natural gas and NGL production	0	0	0	0
Production taxes	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services				(391)
General and administrative	0	0	0	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies		0	0	0
Oil, natural gas and NGL depreciation, depletion and amortization	(1)	(18)	(20)	(57)
Depreciation and amortization of other assets	0	0	0	(64)
Impairment of oil and natural gas properties	(33)	(104)	(431)	(202)
Impairments of fixed assets and other	0	0	0	0
Net gains (losses) on sales of fixed assets	0	0	0	0
Total Operating Expenses	(34)	(122)	(451)	(714)
INCOME FROM OPERATIONS	34	122	451	233
OTHER INCOME (EXPENSE):
Interest expense	152	172	455	498
Income (Loss) from Equity Method Investments	0	0	0	2
Net gain (loss) on sales of investments				0
Losses on purchases of debt				0
Other income (expense)	(29)	(172)	(102)	(524)
Proceeds from Equity Method Investment, Dividends or Distributions	4,644	(679)	12,289	(1,224)
Total Other Expense	4,767	(679)	12,642	(1,248)
INCOME (LOSS) BEFORE INCOME TAXES	4,801	(557)	13,093	(1,015)
Total Income Tax Expense (Benefit)	26	47	189	81
NET INCOME (LOSS)	4,775	(604)	12,904	(1,096)
Net income attributable to noncontrolling interests	(13)	(30)	(50)	(110)
Net income (loss) attributable to Chesapeake	4,762	(634)	12,854	(1,206)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 4,762	$ (634)	$ 12,854	$ (1,206)

Condensed Consolidating Fina102

Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	$ 1,055	$ 3,805
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,696)	(3,185)
Acquisitions of proved and unproved properties	(407)	(1,023)
Proceeds from divestitures of proved and unproved properties	188	723
Additions to other property and equipment	(114)	(675)
Other investing activities	0	(4)
Net Cash Used In Investing Activities	(2,905)	(2,938)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	(143)
Proceeds from credit facilities borrowings	0	3,573
Payments on credit facilities borrowings	0	(3,896)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	394
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	(3,362)
Other financing activities	(32)	(25)
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	(499)	(1,614)
Net increase (decrease) in cash and cash equivalents	(2,349)	(747)
Cash and cash equivalents, beginning of period	4,108	837
Cash and cash equivalents, end of period	1,759	90
Parent Company Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		0
Payments on credit facilities borrowings		0
Proceeds from issuance of senior notes, net of discount and offering costs		2,966
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		(3,362)
Other financing activities	(631)	(293)
Intercompany advances, net	(1,620)	(99)
Net Cash Used In Financing Activities	(2,251)	(788)
Net increase (decrease) in cash and cash equivalents	(2,251)	(788)
Cash and cash equivalents, beginning of period	4,100	799
Cash and cash equivalents, end of period	1,849	11
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	950	3,423
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,633)	(3,090)
Acquisitions of proved and unproved properties	(407)	(1,020)
Proceeds from divestitures of proved and unproved properties	151	722
Additions to other property and equipment	(118)	(424)
Other investing activities	60	1,162
Net Cash Used In Investing Activities	(2,947)	(2,650)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		2,856
Payments on credit facilities borrowings		(2,797)
Proceeds from issuance of senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	387	(1,352)
Intercompany advances, net	1,620	520
Net Cash Used In Financing Activities	2,007	(773)
Net increase (decrease) in cash and cash equivalents	10	0
Cash and cash equivalents, beginning of period	2	0
Cash and cash equivalents, end of period	12	0
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	105	382
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(63)	(95)
Acquisitions of proved and unproved properties	0	(3)
Proceeds from divestitures of proved and unproved properties	37	1
Additions to other property and equipment	4	(251)
Other investing activities	52	60
Net Cash Used In Investing Activities	30	(288)
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	(143)
Proceeds from credit facilities borrowings		717
Payments on credit facilities borrowings		(1,099)
Proceeds from issuance of senior notes, net of discount and offering costs		494
Proceeds from issuance of oilfield services term loan, net of issuance costs		394
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	(75)	(127)
Intercompany advances, net	0	(421)
Net Cash Used In Financing Activities	(218)	(42)
Net increase (decrease) in cash and cash equivalents	(83)	52
Cash and cash equivalents, beginning of period	84	38
Cash and cash equivalents, end of period	1	90
Eliminations [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	0	0
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	12	0
Net Cash Used In Investing Activities	12	0
CASH FLOWS FROM FINANCING ACTIVITIES:
Cash paid to repurchase noncontrolling interest of CHK C-T	0
Proceeds from credit facilities borrowings		0
Payments on credit facilities borrowings		0
Proceeds from issuance of senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	(37)	(11)
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	(37)	(11)
Net increase (decrease) in cash and cash equivalents	(25)	(11)
Cash and cash equivalents, beginning of period	(78)	0
Cash and cash equivalents, end of period	(103)	(11)
Consolidated Entities [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Other investing activities	124	1,222
CASH FLOWS FROM FINANCING ACTIVITIES:
Other financing activities	$ (356)	$ (1,783)

Condensed Consolidating Fina103

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Sep. 30, 2015
Senior Notes [Member]
Condensed Financial Statements, Captions [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	100.00%