Expand Energy (EXE) 10-Q 5 Aug 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
Document and Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
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		665,366,523

CONDENSED CONSOLIDATED BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS - Entity [Domain] - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
CURRENT ASSETS:
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$ 2,051	$ 4,108
Restricted cash	38	38
Accounts receivable, net	1,501	2,236
Short-term derivative assets ($5 and $16 attributable to our VIE)	387	879
Other current assets	254	207
Total Current Assets	4,231	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)	62,161	58,594
Unproved properties	8,625	9,788
Other property and equipment	3,038	3,083
Total Property and Equipment, at Cost	73,824	71,465
Less: accumulated depreciation, depletion and amortization (($361) and ($251) attributable to our VIE)	(50,302)	(39,043)
Property and equipment held for sale, net	93	93
Total Property and Equipment, Net	23,615	32,515
LONG-TERM ASSETS:
Investments	255	265
Long-term derivative assets	186	6
Other long-term assets	311	497
TOTAL ASSETS	28,598	40,751
CURRENT LIABILITIES:
Accounts payable	1,284	2,049
Current maturities of long-term debt, net	889	381
Accrued interest	153	150
Deferred income tax liabilities	126	207
Short-term derivative liabilities	27	15
Other current liabilities ($11 and $15 attributable to our VIE)	2,649	3,061
Total Current Liabilities	5,128	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	10,655	11,154
Deferred income tax liabilities	1,408	4,185
Long-term derivative liabilities	155	218
Asset retirement obligations, net of current portion	460	447
Other long-term liabilities	549	679
Total Long-Term Liabilities	13,227	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: 665,060,856 and 664,944,232 shares issued	7	7
Paid-in capital	12,420	12,531
Retained earnings (deficit)	(6,364)	1,483
Accumulated other comprehensive loss	(131)	(143)
Less: treasury stock, at cost; 1,586,305 and 1,614,312 common shares	(36)	(37)
Total Chesapeake Stockholders’ Equity	8,958	16,903
Noncontrolling interests	1,285	1,302
Total Equity	10,243	18,205
TOTAL LIABILITIES AND EQUITY	$ 28,598	$ 40,751

CONDENSED CONSOLIDATED BALANCE3

CONDENSED CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Millions	Jun. 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	665,060,856	664,944,232
Treasury stock, shares	1,586,305	1,614,312
Cash and cash equivalents	$ 2,051	$ 4,108
Short-term derivative assets ($5 and $16 attributable to our VIE)	387	879
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	62,161	58,594
Less: accumulated depreciation, depletion and amortization (($361) and ($251) attributable to our VIE)	(50,302)	(39,043)
Other current liabilities ($11 and $15 attributable to our VIE)	2,649	3,061
Variable Interest Entities, Primary Beneficiary [Member]
Cash and cash equivalents	1	1
Short-term derivative assets ($5 and $16 attributable to our VIE)	5	16
Proved oil and natural gas properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($361) and ($251) attributable to our VIE)	(361)	(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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES:
Oil, natural gas and NGL	$ 728	$ 1,704	$ 1,813	$ 3,471
Marketing, gathering and compression	2,305	3,167	3,980	6,182
Oilfield services	0	281	0	545
Total Revenues	3,033	5,152	5,793	10,198
OPERATING EXPENSES:
Oil, natural gas and NGL production	276	282	575	570
Production taxes	34	72	62	122
Marketing, gathering and compression	2,096	3,166	3,796	6,147
Oilfield services	0	212	0	431
General and administrative	69	90	125	169
Restructuring and other termination costs	(4)	33	(14)	26
Provision for legal contingencies	334	0	359	0
Oil, natural gas and NGL depreciation, depletion and amortization	601	661	1,285	1,288
Depreciation and amortization of other assets	34	79	69	157
Impairment of oil and natural gas properties	5,015	0	9,991	0
Impairments of fixed assets and other	84	40	88	60
Net (gains) losses on sales of fixed assets	1	(93)	4	(115)
Total Operating Expenses	8,540	4,542	16,340	8,855
INCOME (LOSS) FROM OPERATIONS	(5,507)	610	(10,547)	1,343
OTHER INCOME (EXPENSE):
Interest expense	(71)	(27)	(122)	(66)
Losses on investments	(17)	(24)	(24)	(45)
Net gain on sales of investments	0	0	0	67
Losses on purchases of debt	0	(195)	0	(195)
Other income (expense)	(1)	7	5	13
Total Other Expense	(89)	(239)	(141)	(226)
INCOME (LOSS) BEFORE INCOME TAXES	(5,596)	371	(10,688)	1,117
INCOME TAX EXPENSE (BENEFIT):
Current income taxes	(6)	5	(6)	8
Deferred income taxes	(1,500)	136	(2,872)	413
Total Income Tax Expense (Benefit)	(1,506)	141	(2,878)	421
NET INCOME (LOSS)	(4,090)	230	(7,810)	696
Net income attributable to noncontrolling interests	(18)	(39)	(37)	(80)
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	(4,108)	191	(7,847)	616
Preferred stock dividends	(43)	(43)	(86)	(86)
Earnings allocated to participating securities	0	(3)	0	(12)
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$ (4,151)	$ 145	$ (7,933)	$ 518
EARNINGS (LOSS) PER COMMON SHARE:
Earnings Per Share, Basic	$ (6.27)	$ 0.22	$ (11.99)	$ 0.79
Earnings Per Share, Diluted	(6.27)	0.22	(11.99)	0.78
CASH DIVIDEND DECLARED PER COMMON SHARE	$ 0	$ 0.0875	$ 0.0875	$ 0.1750
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):
Weighted Average Number of Shares Outstanding, Basic	662	659	662	658
Weighted Average Number of Shares Outstanding, Diluted	662	659	662	760

CONDENSED CONSOLIDATED STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
NET INCOME (LOSS)	$ (4,090)	$ 230	$ (7,810)	$ 696
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0 , $1, ($1) and $3	0	0	(1)	3
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $4, $9 and $10	3	(1)	13	10
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)	3	(1)	12	8
COMPREHENSIVE INCOME (LOSS)	(4,087)	229	(7,798)	704
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(18)	(39)	(37)	(80)
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$ (4,105)	$ 190	$ (7,835)	$ 624

CONDENSED CONSOLIDATED STATEME6

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0 , $1, ($1) and $3	$ 0	$ 1	$ (1)	$ 3
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	2	4	9	10
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	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ (7,810)	$ 696
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:
Depreciation, depletion and amortization	1,354	1,445
Deferred income tax expense (benefit)	(2,872)	413
Derivative (gains) losses, net	(344)	542
Cash receipts (payments) on derivative settlements, net	631	(323)
Stock-based compensation	43	40
Impairment of oil and natural gas properties	9,991	0
Net (gains) losses on sales of fixed assets	4	(115)
Impairments of fixed assets and other	81	51
Losses on investments	24	45
Net gains on sales of investments	0	(67)
Losses on purchases of debt	0	61
Restructuring and other termination costs	(14)	24
Provision for legal contingencies	359	0
Other	69	71
Changes in assets and liabilities	(779)	(240)
Net Cash Provided By Operating Activities	737	2,643
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,168)	(1,996)
Acquisitions of proved and unproved properties	(266)	(356)
Proceeds from divestitures of proved and unproved properties	14	248
Additions to other property and equipment	(93)	(620)
Proceeds from sales of other property and equipment	7	713
Additions to investments	(6)	(5)
Proceeds from sales of investments	0	239
Other	0	(3)
Net Cash Used In Investing Activities	(2,512)	(1,780)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	857
Payments on credit facilities borrowings	0	(1,239)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services senior notes, net of discount and offering 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)	(117)
Cash paid for preferred stock dividends	(86)	(86)
Cash paid on financing derivatives	0	(32)
Cash held and retained by SSE at spin-off	0	(8)
Distributions to noncontrolling interest owners	(57)	(105)
Other	(21)	0
Net Cash Used In Financing Activities	(282)	(238)
Net increase (decrease) in cash and cash equivalents	(2,057)	625
Cash and cash equivalents, beginning of period	4,108	837
Cash and cash equivalents, end of period	2,051	1,462
SUPPLEMENTAL CASH FLOW INFORMATION:
Interest paid, net of capitalized interest	65	88
Income taxes paid, net of refunds received	60	13
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:
Change in accrued drilling and completion costs	(46)	(125)
Change in accrued acquisitions of proved and unproved properties	(31)	(60)
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

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				23
Exercise of stock options				23
Dividends on common stock				0	(117)
Dividends on preferred stock				0	(86)
Spin-off of oilfield services business (Note 14)	$ (268)
Increase (decrease) in tax benefit from stock-based compensation				3
Net income (loss) attributable to Chesapeake	616				616
Hedging activity						13
Investment activity						(5)
Purchase of 28,298 and 15,532 shares for company benefit plans							0
Release of 56,305 and 300,034 shares from company benefit plans							5
Chesapeake stockholders’ equity, end of period at Jun. 30, 2014		$ 3,062	$ 7	12,495	833	(154)	(41)	$ 16,202
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2013									$ 2,145
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	80								80
Distributions to noncontrolling interest owners									(102)
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Jun. 30, 2014									2,123
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	18,325
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				40
Exercise of stock options				0
Dividends on common stock				(59)	0
Dividends on preferred stock				(86)	0
Spin-off of oilfield services business (Note 14)					0
Increase (decrease) in tax benefit from stock-based compensation				(6)
Net income (loss) attributable to Chesapeake	(7,847)				(7,847)
Hedging activity						12
Investment activity						0
Purchase of 28,298 and 15,532 shares for company benefit plans							0
Release of 56,305 and 300,034 shares from company benefit plans							1
Chesapeake stockholders’ equity, end of period at Jun. 30, 2015	8,958	$ 3,062	$ 7	$ 12,420	$ (6,364)	$ (131)	$ (36)	$ 8,958
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2014	1,302								1,302
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income attributable to noncontrolling interests	37								37
Distributions to noncontrolling interest owners									(54)
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Jun. 30, 2015	1,285								$ 1,285
Increase (Decrease) in Stockholders' Equity [Roll Forward]
TOTAL EQUITY	$ 10,243

CONDENSED CONSOLIDATED STATEME9

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) - Treasury Stock - Common [Member] - shares	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Purchase of shares for company benefit plans, shares	28,298	15,532
Release of shares from company benefit plans, shares	56,305	300,034

Basis of Presentation and Summa

Basis of Presentation and Summary of Significant Accounting Policies (Note)	6 Months Ended
	Jun. 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 six months ended June 30, 2015 (the "Current Quarter" and the “Current Period”, respectively) and the three and six months ended June 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)	6 Months Ended
	Jun. 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 June 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 Participating securities $ — 1 Three Months Ended June 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 22 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 Net Income Adjustments Shares ($ in millions) (in millions) Six Months Ended June 30, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 43 59 5.75% cumulative convertible preferred stock (series A) $ 32 42 5.00% cumulative convertible preferred stock (series 2005B) $ 5 6 4.50% cumulative convertible preferred stock $ 6 6 Participating securities $ — 2 Six Months Ended June 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.00% cumulative convertible preferred stock (series 2005B) $ 5 6 4.50% cumulative convertible preferred stock $ 6 6 Participating securities $ 11 3 For the Prior Period, the following outstanding equity securities convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the Prior Period is as follows: Income (Numerator) Weighted Average Shares (Denominator) Per Share Amount (in millions, except per share data) Six Months Ended June 30, 2014 Basic EPS $ 518 658 $ 0.79 Effect of Dilutive Securities: Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: Common shares assumed issued for 5.75% cumulative convertible preferred stock 43 59 Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) 32 42 Outstanding stock options — 1 Diluted EPS $ 593 760 $ 0.78

Debt (Note)

Debt (Note)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Debt Disclosure	Debt Our long-term debt consisted of the following as of June 30, 2015 and December 31, 2014: June 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) (188 ) (231 ) Interest rate derivatives (d) 8 10 Total debt, net 11,544 11,535 Less current maturities of long-term debt, net (e) (889 ) (381 ) Total long-term debt, net $ 10,655 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.1147 to €1.00 and $1.2098 to €1.00 as of June 30, 2015 and December 31, 2014, respectively. See 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 holders of our 2.75% Contingent Convertible Senior Notes due 2035 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. 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 second 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 third 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. (c) Discount as of June 30, 2015 and December 31, 2014 included $181 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 Note 8 for further discussion related to these instruments. (e) As of June 30, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016 and 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (b) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 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 June 30, 2015 and December 31, 2014, current maturities of long-term debt, net reflects $7 million and $15 million , respectively, of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035. Chesapeake Senior Notes and Contingent Convertible Senior Notes The Chesapeake senior notes and the contingent convertible senior notes are unsecured senior obligations of Chesapeake and rank equally in right of payment with all of our other existing and future senior unsecured indebtedness and rank senior in right of payment to all of our future subordinated indebtedness. Chesapeake is a holding company, 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 18 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. The senior notes and contingent convertible senior notes indentures 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. The District Court held argument on the motion and cross-motion on May 1, 2015. On July 10, 2015, the District Court granted the Trustee’s motion and denied the Company’s cross-motion and entered an amended judgment on July 17, 2015 awarding the Trustee $380 million plus prejudgment interest in the amount of $59 million . The Company filed a notice of appeal on July 27, 2015 and posted a supersedeas bond to stay execution of the judgment while appellate proceedings are pending. Revolving Credit Facility In December 2014, we entered into a five -year $4.0 billion senior unsecured revolving credit facility to use for general corporate purposes. The credit facility replaced our then-existing $4.0 billion senior secured revolving credit facility. The aggregate commitments under the facility may be increased up to an additional $1.0 billion , and the December 2019 maturity date may be extended for two one -year periods at our request and with the consent of the participating lenders. As of June 30, 2015 , we had no outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are currently unsecured; however, we will be required to provide collateral and the facility will be subject to a borrowing base if our credit rating declines to Ba3 (Moody’s Investors Services, Inc.) or BB- (Standard & Poor’s Ratings Services) or lower. Revolving loans under the credit facility bear interest at a fluctuating rate per annum equal to the highest of (i) the federal funds effective rate plus 0.5% , (ii) the administrative agent’s prime rate or (iii) the London interbank offer rate (LIBOR) for a one-month interest period plus 1.0% (alternative base rate (ABR) loans), and/or LIBOR rates (LIBOR loans), at our election, plus an applicable margin rate depending on our credit rating (currently 0.625% per annum for ABR loans and 1.625% per annum for LIBOR loans). The terms of the credit facility include covenants limiting, among other things, the ability of the Company and its restricted subsidiaries 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 . In addition, the credit facility requires us to maintain, as of the last day of each fiscal quarter, (i) a net debt to capitalization ratio (as defined in the credit agreement) that does not exceed 65 %; and (ii) a leverage ratio (net debt to consolidated EBITDA, as defined in the credit agreement) that does not exceed 4.0 to 1.0 ; provided, however, that the leverage ratio will not apply during any period in which our credit rating, as determined by either Moody’s Investors Services, Inc. or Standard & Poor’s Rating Services, meets certain investment grade thresholds, as defined in the credit agreement. Our credit facility is fully and unconditionally guaranteed, on a joint and several basis, by certain of our material subsidiaries. The 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 an independent, publicly traded company called Seventy Seven Energy Inc. (SSE). In the Prior Quarter, 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 $391 million to us, to repay a portion of outstanding indebtedness under the new revolving credit facility discussed above and for general corporate purposes. All deferred charges and debt balances related to these transactions were removed from our consolidated balance sheet as of June 30, 2014. See Note 14 for further discussion of the spin-off. Fair Value of Debt We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which would include borrowings under our revolving credit facility (which was undrawn as of June 30, 2015 and December 31, 2014), is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. June 30, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 889 $ 892 $ 381 $ 396 Long-term debt (Level 1) $ 10,647 $ 10,286 $ 11,144 $ 11,656

Contingencies and Commitments (

Contingencies and Commitments (Note)	6 Months Ended
	Jun. 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 plaintiff 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. 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 allege 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. With the dismissal of the federal securities class action now affirmed (in July 2014), the parties stipulated to continue the stay of the Oklahoma state court derivative action while the plaintiffs pursue 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. 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 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. On March 5, 2014, the Attorney General of the State of Michigan filed a criminal complaint against Chesapeake in Michigan state court alleging misdemeanor antitrust violations and attempted antitrust violations under state law arising out of the Company’s leasing activities in Michigan during 2010. On July 9, 2014, following a preliminary hearing on the complaint, as amended, the 89 th District Court for Cheboygan County, Michigan ruled that one count alleging a bid-rigging conspiracy between Chesapeake and Encana Oil & Gas USA, Inc. regarding the October 2010 state lease auction would proceed to trial and dismissed claims alleging a second antitrust violation and an attempted antitrust violation. The Michigan Attorney General filed a second criminal complaint against Chesapeake in the same court on June 5, 2014 which, as amended, alleged that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. In resolution of both criminal complaints and with no admission of wrongdoing, on April 24, 2015, the Company entered a plea of no contest to one count of misdemeanor attempted antitrust violation and one count of misdemeanor false pretenses. The plea has been taken under advisement for a period of 11 months by the Court and will be dismissed if Chesapeake fulfills the terms of a settlement agreement with the Attorney General. As part of the settlement, Chesapeake will contribute no more than $25 million to a compensation fund established to compensate Michigan landowners for unfunded oil and gas leases in 2010. 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 Quarter 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). 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 for royalty underpayment in various states, including, but not limited to, Oklahoma, Texas, Pennsylvania, Ohio, 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 and state subpoenas seeking information on the Company’s royalty payment practices. Plaintiffs have varying royalty provisions in their respective leases and oil and gas law varies from state to state. Royalty owners and producers differ in their interpretation of the legal effect of lease provisions governing royalty calculations, an issue in a putative class action filed in November 2010 in the District Court of Beaver County, Oklahoma on behalf of Oklahoma royalty owners asserting claims dating back to 2004. In July 2014, this case was remanded to the trial court for further proceedings following the reversal on appeal of certification of a statewide class. We and the named plaintiff participated in mediation concerning the claims asserted in the putative class action litigation, and in the Current Period we negotiated a settlement requiring the Company to pay $119 million cash to compensate the putative settlement class for alleged past royalty underpayments in exchange for the release of claims for the ten-year period ended December 31, 2014. Following a fairness hearing, the District Court certified the settlement class and approved the $119 million settlement on July 3, 2015. The Company reduced its prior settlement accrual to $114 million in the Current Quarter to reflect potential claimants that have opted out of the settlement. Although Chesapeake believes its royalty calculation and payment methodologies are appropriate under Oklahoma oil and gas law and denies that it committed any acts or omissions giving rise to any liability, it also believes that settlement is in the best interest of the Company considering the questions of law and fact involved and the uncertainty of continued litigation. Chesapeake is also defending lawsuits 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 are primarily related 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 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. 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 will vary depending on the applicable agreement. Two of these agreements, one for production in the Anadarko Basin in northwestern Oklahoma and the Texas panhandle and the other for production in the Haynesville/Bossier Shales in northwestern Louisiana, contain cost-of-service based fees that are redetermined annually through 2019 and 2020, respectively. The annual upward or downward fee adjustment for these two contracts 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. 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 discussed above, are presented below. June 30, ($ in millions) 2015 $ 914 2016 1,936 2017 1,941 2018 1,723 2019 1,437 2020 – 2099 6,227 Total $ 14,178 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 June 30, 2015 , the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $353 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 June 30, 2015 , the aggregate undiscounted minimum future payments under this agreement were approximately $185 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. Natural Gas and Liquids Purchase Commitments We regularly commit to purchase natural gas and liquids from other owners in the properties we operate, including owners associated with our volumetric production payment (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. See Note 9 for further discussion of our VPP transactions. Net Acreage Maintenance Commitments Under the terms of our joint venture agreements with Total S.A. (see 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. 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, subject to the occurrence of specified milestones. As of June 30, 2015 , we had funded our $155 million commitment in full and the milestones related to Sundrop’s preferred equity call option had not been met. 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 Note 9 for further discussion of our VPP transactions. While executing our strategic priorities, we have incurred certain cash charges, including contract termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity. As we continue to focus on our strategic priorities, we may take certain actions that reduce financial leverage and complexity, and we may incur additional cash and noncash charges.

Other Liabilities (Note)

Other Liabilities (Note)	6 Months Ended
	Jun. 30, 2015
Other Liabilities Disclosure [Abstract]
Other Liabilities Disclosure	Other Liabilities Other current liabilities as of June 30, 2015 and December 31, 2014 are detailed below. June 30, December 31, ($ in millions) Revenues and royalties due others $ 757 $ 1,176 Accrued drilling and production costs 327 385 Joint interest prepayments received 202 189 Accrued compensation and benefits 237 344 Other accrued taxes 130 55 Accrued dividends 43 101 Bank of New York Mellon legal accrual 439 100 Oklahoma royalty settlement 114 119 Other 400 592 Total other current liabilities $ 2,649 $ 3,061 Other long-term liabilities as of June 30, 2015 and December 31, 2014 are detailed below. June 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 205 $ 220 CHK C-T ORRI conveyance obligation (b) 128 135 Financing obligations 29 30 Unrecognized tax benefits 46 45 Other 141 249 Total other long-term liabilities $ 549 $ 679 ____________________________________________ (a) $20 million and $14 million of the total $225 million and $234 million obligations are recorded in other current liabilities as of June 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation. (b) $28 million and $23 million of the total $156 million and $158 million obligations are recorded in other current liabilities as of June 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation.

Equity (Note)

Equity (Note)	6 Months Ended
	Jun. 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: Six 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) 103 (2,019 ) Stock option exercises 14 1,268 Shares issued as of June 30 665,061 665,441 ___________________________________________ (a) In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock were previously issued on the date the RSAs were granted. We refer to RSAs and RSUs collectively as restricted stock. 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 June 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 (1 ) — (1 ) Amounts reclassified from accumulated other comprehensive income 13 — 13 Net other comprehensive income 12 — 12 Balance, June 30, 2015 $ (131 ) $ — $ (131 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 3 — 3 Amounts reclassified from accumulated other comprehensive income 10 (5 ) 5 Net other comprehensive income 13 (5 ) 8 Balance, June 30, 2014 $ (154 ) $ — $ (154 ) 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 June 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 3 Total reclassifications for the period, net of tax $ 3 Three Months Ended June 30, 2014 Net gains on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ (1 ) Total reclassifications for the period, net of tax $ (1 ) Six Months Ended June 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 13 Total reclassifications for the period, net of tax $ 13 Six Months Ended June 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 10 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 5 Noncontrolling Interests Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (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. CHK C-T is an unrestricted subsidiary under our revolving credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. 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. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement, as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheets. Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. CHK C-T is required to retain an amount of cash equal to the next two quarters of preferred dividend payments. The amount reserved, approximately $38 million as of June 30, 2015 and December 31, 2014, was reflected as restricted cash on our condensed consolidated balance sheets. We initially committed to drill and complete, for the benefit of CHK C-T in the area of mutual interest, a minimum of 37.5 net wells per six-month period through 2013, inclusive of wells drilled in 2012, and 25 net wells per six-month period in 2014 through 2016, up to a minimum cumulative total of 300 net wells. In April 2014, the drilling commitment was amended to require us to drill and complete a minimum cumulative total of (i) 162.5 net wells by June 30, 2014 and (ii) 175 net wells by December 31, 2014. The drilling commitment was suspended in January 2015. The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in CHK C-T wells is subject to an increase to 5% on net wells earned in any year following a year in which we do not meet our net well commitment under the ORRI obligation. We did not meet the 2014 ORRI conveyance commitment. However, in no event are we required to deliver to investors more than a total ORRI of 3.75% in the contributed wells and 1,000 future net wells. As of June 30, 2015 , we had drilled 190 net wells. The obligation to deliver future ORRIs, which runs through the first quarter of 2025, has been recorded as a liability that will be settled through the 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. As of June 30, 2015 and December 31, 2014 , $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK C-T. For the Current Quarter and the Prior Quarter, income of $19 million was attributable to the noncontrolling interests of CHK C-T and for the Current Period and the Prior Period, income of $38 million was attributable to the noncontrolling interests of CHK C-T. On June 30, 2015, we entered into an agreement to sell all of the properties held by CHK C-T to FourPoint Energy, LLC (FourPoint) for approximately $575 million . We will use the consideration from the sale and cash held by CHK C-T, to repurchase the outstanding preferred shares in CHK C-T, subject to customary adjustments to the purchase price and certain indemnity obligations in connection with the sale. Upon closing of the transaction, we will eliminate the noncontrolling interest and ORRI obligation on our condensed consolidated balance sheet, approximately $75 million in annual preferred dividend payments and all related future drilling and ORRI commitments attributable to CHK C-T. We expect this transaction to close in the 2015 third quarter. 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 June 30, 2015 , we had drilled 463 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 $19 million and $37 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 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, or cause to be drilled, 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 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 June 30, 2015 and 2014 , we had drilled or caused to be drilled approximately 104 and 93 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $32 million and $55 million , respectively. 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 12 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 June 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 December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — 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 June 30, 2015 and December 31, 2014 , $271 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 a loss of approximately $1 million in the Current Quarter, income of approximately $2 million in the Prior Quarter, a loss of approximately $1 million in the Current Period and income of approximately $7 million in the Prior Period. See Note 11 for further discussion of VIEs.

Share-Based Compensation (Note)

Share-Based Compensation (Note)	6 Months Ended
	Jun. 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 to employees and non-employee directors. 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 6,918 $ 14.03 Vested (2,651 ) $ 16.79 Forfeited (374 ) $ 15.28 Unvested restricted stock as of June 30, 2015 13,984 $ 18.65 The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $45 million based on the stock price at the time of vesting. As of June 30, 2015 , there was approximately $180 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 2.21 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 and the Current Period, we recognized reductions in tax benefits related to restricted stock of a nominal amount and $6 million , respectively, and during the Prior Quarter and the Prior Period, we recognized excess tax benefits related to restricted stock of a nominal amount and $3 million , respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes. Stock Options. In the Current Period and the Prior Period, we granted members of senior management stock options that vest ratably over a three -year period. In January 2013, we also granted retention awards of stock options to certain officers that vest one-third on each of the third , fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant. We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period: Expected option life – years 4.5 Volatility 39.91 % Risk-free interest rate 1.33 % Dividend yield 1.91 % The following table provides information related to stock option activity for the Current Period: Number of Shares Underlying Options Weighted Average Exercise Price Per Share Weighted Average Contract Life in Years Aggregate Intrinsic Value (a) (in thousands) ($ 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 June 30, 2015 5,580 $ 19.33 6.39 $ — Exercisable at June 30, 2015 2,169 $ 19.44 5.59 $ — ___________________________________________ (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 June 30, 2015 , there was $13 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.02 years . The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in these benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter and the Current Period, we recognized a reduction in tax benefits related to stock options of nominal amounts, and during the Prior Quarter and the Prior Period, we recognized nominal amounts of excess tax benefits related to stock options. Each adjustment was recorded to additional paid-in capital and deferred income taxes. Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 12 $ 11 $ 24 $ 24 Oil and natural gas properties 8 9 15 16 Oil, natural gas and NGL production expenses 6 5 10 8 Marketing, gathering and compression expenses 2 1 3 3 Oilfield services expenses — 3 — 5 Total $ 28 $ 29 $ 52 $ 56 Liability-Classified Awards Performance Share Units. In 2013, 2014 and 2015, we granted PSUs to senior management that vest ratably over their respective terms 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 40.12 % Risk-free interest rate 0.95 % Dividend yield for value of awards 1.91 % 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 $ 13 $ 12 2014 Awards: Payable 2017 609,637 $ 16 $ 1 $ 1 2015 Awards: Payable 2018 696,683 $ 13 $ 5 $ 2 ___________________________________________ (a) As of June 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (4 ) $ 11 $ (14 ) $ 10 Restructuring and other termination costs (5 ) 15 (15 ) 6 Marketing, gathering and compression — 1 (1 ) 1 Oil and natural gas properties — 2 (1 ) 3 Total $ (9 ) $ 29 $ (31 ) $ 20 Effect of the Spin-off on Share-Based Compensation The employee matters agreement entered into in connection with the spin-off of our oilfield services business (see Note 14) 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)	6 Months Ended
	Jun. 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 June 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 June 30, 2015 and December 31, 2014 are provided below. June 30, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 7.4 $ 196 12.5 $ 471 Three-way collars 2.2 21 4.4 40 Call options 27.9 (26 ) 35.8 (89 ) Basis protection swaps 4.5 4 — — Total oil 42.0 $ 195 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 260 $ 135 275 $ 281 Three-way collars 71 51 207 165 Call options 193 (128 ) 193 (170 ) Basis protection swaps 80 5 60 23 Total natural gas 604 $ 63 735 $ 299 Total estimated fair value $ 258 $ 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 June 30, 2015 and 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 June 30, 2015 and December 31, 2014 was $400 million and $850 million , respectively. The estimated fair value of our interest rate derivative liabilities as of June 30, 2015 and December 31, 2014 was a nominal amount and $17 million , respectively. We have terminated certain fair value hedges related to 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 $88 million and $53 million as of June 30, 2015 and December 31, 2014 , respectively. The euro-denominated debt in long-term debt has been adjusted to $384 million as of June 30, 2015 , using an exchange rate of $1.1147 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. As of June 30, 2015 , two supply contracts comprise our supply contract derivatives . In the Current Quarter, we were required to bifurcate a derivative embedded within one of our supply contracts. Under this contract, we are committed to supply approximately 90,000 mmbtu per day of natural gas through March 2025. In the Current Quarter and the Current Period, we recorded revenues of approximately $27 million for settlements of this embedded derivative. As of June 30, 2015 , the bifurcated derivative was measured to fair value, which resulted in a $221 million unrealized gain. Both settlements and mark-to market gains (losses) are included in marketing, gathering and compression revenues in our condensed consolidated statements of operations. Effect of Derivative Instruments – Condensed Consolidated Balance Sheets The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014 on a gross basis and after same-counterparty netting: Balance Sheet Classification Gross Fair Value Amounts Netted in Condensed Consolidated Balance Sheet Net Fair Value Presented in Condensed Consolidated Balance Sheet ($ in millions) As of June 30, 2015 Commodity Contracts: Short-term derivative asset $ 426 $ (74 ) $ 352 Short-term derivative liability (101 ) 74 (27 ) Long-term derivative liability (67 ) — (67 ) Total commodity contracts 258 — 258 Interest Rate Contracts: Short-term derivative liability — — — Total interest rate contracts — — — Foreign Currency Contracts: (a) Long-term derivative liability (88 ) — (88 ) Total foreign currency contracts (88 ) — (88 ) Supply Contracts: Short-term derivative asset 35 — 35 Long-term derivative asset 186 — 186 Total supply contracts 221 — 221 Total derivatives $ 391 $ — $ 391 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 June 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 sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 776 $ 1,917 $ 1,700 $ 4,065 Gains (losses) on undesignated oil and natural gas derivatives (43 ) (210 ) 135 (574 ) Losses on terminated cash flow hedges (5 ) (3 ) (22 ) (20 ) Total oil, natural gas and NGL sales $ 728 $ 1,704 $ 1,813 $ 3,471 The components of marketing, gathering and compression sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression sales (a) $ 2,085 $ 3,167 $ 3,760 $ 6,182 Gains on undesignated supply contract derivatives 220 — 220 — Total marketing, gathering and compression sales $ 2,305 $ 3,167 $ 3,980 $ 6,182 ____________________________________________ (a) Current Quarter and Current Period settlements of $27 million on supply contracts accounted for as derivatives are reflected in marketing, gathering and compression revenues. The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Interest expense on senior notes $ 171 $ 184 $ 342 $ 364 Interest expense on term loan — 7 — 36 Amortization of loan discount, issuance costs and other 12 16 23 35 Interest expense on credit facilities 3 9 6 17 Gains on terminated fair value hedges (1 ) (1 ) (2 ) (2 ) Gains on undesignated interest rate derivatives — (33 ) (10 ) (51 ) Capitalized interest (114 ) (155 ) (237 ) (333 ) Total interest expense $ 71 $ 27 $ 122 $ 66 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 June 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (216 ) $ (134 ) $ (247 ) $ (153 ) Net change in fair value — — 1 — (Gains) losses reclassified to income 5 3 3 (1 ) Balance, end of period $ (211 ) $ (131 ) $ (243 ) $ (154 ) Six Months Ended June 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 (2 ) (1 ) 6 3 Losses reclassified to income 22 13 20 10 Balance, end of period $ (211 ) $ (131 ) $ (243 ) $ (154 ) Approximately $123 million of the $131 million of accumulated other comprehensive loss as of June 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 June 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 June 30, 2015 , our oil, natural gas, interest rate and supply contract derivative instruments were spread among 17 counterparties. Hedging Arrangements As of June 30, 2015 , our secured commodity hedging facility with 11 counterparties provided approximately 465 mmboe of hedging capacity for oil, natural gas and NGL price derivatives and 465 mmboe for basis derivatives with an aggregate mark-to-market capacity of $7.4 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. Chesapeake has 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 they owe Chesapeake exceed defined thresholds. As of June 30, 2015 , we had hedged under the facility 40.5 mmboe of our future production with price derivatives and 2.3 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 Quarter, we entered into bilateral arrangements that reduced the aggregate mark-to-market capacity under the secured hedging facility from $16.5 billion to $7.4 billion . The counterparties’ obligations under the bilateral hedging agreements must be secured by cash or letters of credit to the extent that any mark-to-market amounts they owe Chesapeake exceed defined thresholds. As of June 30, 2015 , we had hedged under bilateral agreements 84.2 mmboe of our future production with price derivatives and 15.6 mmboe with basis derivatives. Fair Value The fair value of our derivatives is based on third-party pricing models which utilize inputs that are either readily available in the public market, such as oil and natural gas forward curves and discount rates, or can be corroborated from active markets or broker quotes. These values are compared to the values given by our counterparties for reasonableness. Since oil, natural gas, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives. The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of June 30, 2015 and December 31, 2014 : Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) Total Fair Value ($ in millions) As of June 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 353 $ 73 $ 426 Commodity liabilities — (13 ) (155 ) (168 ) Interest rate liabilities — — — — Foreign currency liabilities — (88 ) — (88 ) Supply contract assets — — 221 221 Total derivatives $ — $ 252 $ 139 $ 391 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) (realized/unrealized): Included in earnings (a) 80 220 Total purchases, issuances, sales and settlements: Settlements (108 ) — Ending balance as of June 30, 2015 $ (82 ) $ 221 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (realized/unrealized): Included in earnings (a) (173 ) — Total purchases, issuances, sales and settlements: Settlements 105 — Transfers (b) (4 ) — Ending balance as of June 30, 2014 $ (550 ) $ — ___________________________________________ (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 $ 80 $ (173 ) $ 220 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 69 $ (133 ) $ 220 $ — (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 June 30, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value June 30, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 19.51% – 32.31% 26.97% $ (5 ) Supply contracts (b) Oil price volatility curves 16.55% – 33.27% 20.05% $ 221 Natural gas trades (a) Natural gas price volatility curves 20.47% – 56.46% 32.19% $ (77 ) ___________________________________________ (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)	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
Mergers, Acquisitions and Dispositions Disclosure	Oil and Natural Gas Property Transactions During the Prior Period, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $240 million related to divestitures of noncore oil and natural gas properties. We had no material divestitures in the Current Period. Under full cost accounting rules, we have accounted for the sale of oil and natural gas properties as an adjustment 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 June 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 $357 million , respectively, in drilling and completion carries paid by our joint venture partners. All joint venture carries were fully utilized in the Current Period. 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 $19 million and $8 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 hedges to each of the respective VPP buyers and these hedges 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 June 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 8 September 2010 Barnett Shale 1,150 — 390 — 390 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 $ 5,481 5.2 1,105 14.0 1,220 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 June 30, 2015 Three Months Ended June 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 78.0 2.2 268.7 4.3 103.0 2.7 329.9 5.3 9 42.5 3.5 94.9 4.4 47.5 3.9 103.9 4.8 8 — 13.6 — 13.6 — 15.2 — 15.2 6 (a) — — — — 6.0 1.1 — 1.1 5 (a) — — — — 6.0 1.7 — 1.7 4 10.7 2.0 — 2.1 12.2 2.3 — 2.3 3 — 1.6 — 1.6 — 1.8 — 1.8 2 — 1.0 — 1.0 — 1.6 — 1.6 1 — 3.3 — 3.3 — 3.4 — 3.4 131.2 27.2 363.6 30.3 174.7 33.7 433.8 37.2 Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 161.0 4.4 545.0 8.7 212.0 5.5 675.1 10.8 9 86.1 7.2 191.9 8.9 96.5 7.9 210.4 9.7 8 — 27.6 — 27.6 — 30.9 — 30.9 6 (a) — — — — 12.0 2.2 — 2.3 5 (a) — — — — 12.3 3.4 — 3.5 4 21.7 4.1 — 4.2 24.6 4.6 — 4.7 3 — 3.3 — 3.3 — 3.7 — 3.7 2 — 2.1 — 2.1 — 4.0 — 4.0 1 — 6.8 — 6.8 — 7.0 — 7.0 268.8 55.5 736.9 61.6 357.4 69.2 885.5 76.6 ____________________________________________ (a) 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 June 30, 2015 were as follows: Volume Remaining as of June 30, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 80 1.2 33.6 4.1 65.4 9 68 0.7 66.0 1.7 81.0 8 2 — 8.9 — 8.9 4 18 0.1 11.2 — 11.6 3 49 — 20.6 — 20.6 2 46 — 11.7 — 11.7 1 90 — 84.8 — 84.8 2.0 236.8 5.8 284.0

Investments (Note)

Investments (Note)	6 Months Ended
	Jun. 30, 2015
Investments [Abstract]
Investments Disclosure	Investments A summary of our investments, including our approximate ownership percentage and carrying value as of June 30, 2015 and December 31, 2014 , is presented below. Approximate Ownership % Carrying Value Accounting Method June 30, December 31, June 30, December 31, ($ in millions) FTS International, Inc. Equity 30% 30% $ 106 $ 116 Sundrop Fuels, Inc. Equity 56% 56% 131 130 Other — —% —% 18 19 Total investments $ 255 $ 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 $31 million , for our share of FTS’ net loss and an accretion adjustment of $21 million related to the excess of our underlying equity in net assets of FTS over our carrying value. As of June 30, 2015 , the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $23 million , of which $14 million was attributed to non-depreciable assets. The value attributed to depreciable assets is being accreted over the estimated useful lives of the underlying assets. 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 a $4 million charge related to our share of Sundrop's net loss and $5 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 $83 million as of June 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)	6 Months Ended
	Jun. 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 could potentially 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 June 30, 2015 , $1 million of cash and cash equivalents, $5 million of short-term derivative assets, $488 million of proved oil and natural gas properties, $361 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 June 30, 2015 .

Other Property and Equipment (N

Other Property and Equipment (Note)	6 Months Ended
	Jun. 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) Natural gas compressors $ — $ (94 ) $ — $ (120 ) Gathering systems and treating plants — 10 — 13 Oilfield services equipment — (9 ) — (7 ) Buildings and land — 1 1 1 Other 1 (1 ) 3 (2 ) Total net (gains) losses on sales of fixed assets $ 1 $ (93 ) $ 4 $ (115 ) In the Prior Quarter, we sold 337 compressors and related equipment to Exterran Partners, L.P. for approximately $362 million . We recorded a $93 million gain associated with the transaction. In the Prior Period, we 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 miscellaneous properties located primarily in Oklahoma, West Virginia and the Fort Worth, Texas area. Land and buildings 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 June 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 June 30, 2015 and December 31, 2014 , we had $93 million of buildings and land, net of accumulated depreciation, classified as assets held for sale on our condensed consolidated balance sheets.

Impairments (Note)

Impairments (Note)	6 Months Ended
	Jun. 30, 2015
Asset Impairment Charges [Abstract]
Asset Impairment Charges Disclosure	Impairments Impairments of Oil and Natural Gas Properties Our 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 $5.015 billion and $9.991 billion , respectively. Cash flow hedges as of June 30, 2015 , which related to future periods, increased the ceiling test impairment by $190 million . Based on the first-day-of the-month prices we have received over the 11 months ended August 1, 2015, we expect to record another material write-down in the carrying value of our oil and natural gas properties in the third 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 Quarter, we recorded a $21 million impairment related to 466 compressors as a result of our pending sale of third-party rental compression assets in the Permian Basin and in western Oklahoma. Contract Termination Charges . In the Current Quarter and 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 $3 million and $7 million , respectively. Further contract termination charges in subsequent quarters will 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 Quarter, we recorded a $47 million loss contingency related to contract disputes and a $13 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 Prior Quarter, we revised our estimate of our net acreage shortfall with Total under the terms of our Barnett Shale joint venture agreement and recorded an additional $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.

Spin-Off of Oilfield Services B

Spin-Off of Oilfield Services Business Spin-Off of Oilfield Services Business (Note)	6 Months Ended
	Jun. 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 a corporation named Seventy Seven Energy Inc. • 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 17 for additional information regarding our segments. In the Prior Period, our stockholders’ equity decreased by $268 million , net of $152 million of associated deferred tax liabilities, as the result of the spin-off, and we recognized $12 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	6 Months Ended
	Jun. 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 expected material write-downs of the carrying value of our oil and natural gas properties and our operating results in subsequent quarters, 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)	6 Months Ended
	Jun. 30, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements Disclosure	Fair Value Measurements Recurring Fair Value Measurements Other Current Assets. Assets related to Company matches of employee contributions to Chesapeake’s employee benefit plans 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 June 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 June 30, 2015 Financial Assets (Liabilities): Other current assets $ 62 $ — $ — $ 62 Other current liabilities (63 ) — — (63 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 ) See Note 3 for information regarding fair value of other financial instruments. See Note 8 for information regarding fair value measurement of derivatives. Nonrecurring Fair Value Measurements See Note 13 regarding nonrecurring fair value measurements.

Segment Information (Note)

Segment Information (Note)	6 Months Ended
	Jun. 30, 2015
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]
Segment Information Disclosure	Segment Information As of June 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 $1.204 billion , $2.188 billion , $2.437 billion and $4.596 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 $274 million and $544 million for the Prior Quarter and the Prior Period, respectively. No income was recognized in our condensed consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. The following table presents selected financial information for Chesapeake’s operating segments: Exploration and Production Marketing, Gathering and Compression Former Oilfield Services Other Intercompany Eliminations Consolidated Total ($ in millions) Three Months Ended June 30, 2015 Revenues $ 699 $ 3,509 $ — $ — $ (1,175 ) $ 3,033 Intersegment revenues 29 (1,204 ) — — 1,175 — Total revenues $ 728 $ 2,305 $ — $ — $ — $ 3,033 Income (Loss) Before Income Taxes $ (5,785 ) $ 134 $ — $ (31 ) $ 86 $ (5,596 ) Three Months Ended June 30, 2014 Revenues $ 1,704 $ 5,355 $ 552 $ 3 $ (2,462 ) $ 5,152 Intersegment revenues — (2,188 ) (274 ) — 2,462 — Total revenues $ 1,704 $ 3,167 $ 278 $ 3 $ — $ 5,152 Income (Loss) Before Income Taxes $ 410 $ 109 $ 19 $ (20 ) $ (147 ) $ 371 Six Months Ended June 30, 2015 Revenues $ 1,761 $ 6,417 $ — $ — $ (2,385 ) $ 5,793 Intersegment revenues 52 (2,437 ) — — 2,385 — Total revenues $ 1,813 $ 3,980 $ — $ — $ — $ 5,793 Income (Loss) Before Income Taxes $ (11,134 ) $ 138 $ — $ (45 ) $ 353 $ (10,688 ) Six Months Ended June 30, 2014 Revenues $ 3,471 $ 10,777 $ 1,060 $ 30 $ (5,140 ) $ 10,198 Intersegment revenues — (4,596 ) (544 ) — 5,140 — Total revenues $ 3,471 $ 6,181 $ 516 $ 30 $ — $ 10,198 Income (Loss) Before Income Taxes $ 1,098 $ 213 $ (16 ) $ 39 $ (217 ) $ 1,117 As of June 30, 2015 Total Assets $ 22,815 $ 1,946 $ — $ 4,364 $ (527 ) $ 28,598 As of December 31, 2014 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751

Condensed Consolidating Financi

Condensed Consolidating Financial Information (Note)	6 Months Ended
	Jun. 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 June 30, 2015 and December 31, 2014 and for the three and six months ended June 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 JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 2,148 $ 1 $ 30 $ (128 ) $ 2,051 Restricted cash — — 38 — 38 Other 78 2,013 51 — 2,142 Intercompany receivable, net 24,917 — 365 (25,282 ) — Total Current Assets 27,143 2,014 484 (25,410 ) 4,231 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 19,478 716 1,090 21,284 Other property and equipment, net — 2,237 1 — 2,238 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 21,808 717 1,090 23,615 LONG-TERM ASSETS: Other assets 121 614 27 (10 ) 752 Investments in subsidiaries and intercompany advances (5,967 ) 188 — 5,779 — TOTAL ASSETS $ 21,297 $ 24,624 $ 1,228 $ (18,551 ) $ 28,598 CURRENT LIABILITIES: Current liabilities $ 1,547 $ 3,653 $ 56 $ (128 ) $ 5,128 Intercompany payable, net — 24,785 — (24,785 ) — Total Current Liabilities 1,547 28,438 56 (24,913 ) 5,128 LONG-TERM LIABILITIES: Long-term debt, net 10,655 — — — 10,655 Deferred income tax liabilities — 1,263 78 67 1,408 Other long-term liabilities 137 890 137 — 1,164 Total Long-Term Liabilities 10,792 2,153 215 67 13,227 EQUITY: Chesapeake stockholders’ equity 8,958 (5,967 ) 957 5,010 8,958 Noncontrolling interests — — — 1,285 1,285 Total Equity 8,958 (5,967 ) 957 6,295 10,243 TOTAL LIABILITIES AND EQUITY $ 21,297 $ 24,624 $ 1,228 $ (18,551 ) $ 28,598 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 JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 693 $ 35 $ — $ 728 Marketing, gathering and compression — 2,305 — — 2,305 Total Revenues — 2,998 35 — 3,033 OPERATING EXPENSES: Oil, natural gas and NGL production — 267 9 — 276 Production taxes — 33 1 — 34 Marketing, gathering and compression — 2,096 — — 2,096 General and administrative — 67 2 — 69 Restructuring and other termination costs — (4 ) — — (4 ) Provision for legal contingencies 339 (5 ) — — 334 Oil, natural gas and NGL depreciation, depletion and amortization — 586 23 (8 ) 601 Depreciation and amortization of other assets — 34 — — 34 Impairment of oil and natural gas properties — 5,012 186 (183 ) 5,015 Impairments of fixed assets and other — 84 — — 84 Net losses on sales of fixed assets — 1 — — 1 Total Operating Expenses 339 8,171 221 (191 ) 8,540 LOSS FROM OPERATIONS (339 ) (5,173 ) (186 ) 191 (5,507 ) OTHER INCOME (EXPENSE): Interest expense (180 ) (37 ) — 146 (71 ) Losses on investments — (17 ) — — (17 ) Other income (expense) 81 (7 ) — (75 ) (1 ) Equity in net earnings (losses) of subsidiary (3,792 ) (154 ) — 3,946 — Total Other Expense (3,891 ) (215 ) — 4,017 (89 ) LOSS BEFORE INCOME TAXES (4,230 ) (5,388 ) (186 ) 4,208 (5,596 ) INCOME TAX BENEFIT (122 ) (1,404 ) (50 ) 70 (1,506 ) NET LOSS (4,108 ) (3,984 ) (136 ) 4,138 (4,090 ) Net income attributable to noncontrolling interests — — — (18 ) (18 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (4,108 ) (3,984 ) (136 ) 4,120 (4,108 ) Other comprehensive income — 3 — — 3 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (4,108 ) $ (3,981 ) $ (136 ) $ 4,120 $ (4,105 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,618 $ 88 $ (2 ) $ 1,704 Marketing, gathering and compression — 3,166 1 — 3,167 Oilfield services — 23 499 (241 ) 281 Total Revenues — 4,807 588 (243 ) 5,152 OPERATING EXPENSES: Oil, natural gas and NGL production — 272 10 — 282 Production taxes — 70 2 — 72 Marketing, gathering and compression — 3,166 — — 3,166 Oilfield services — 22 375 (185 ) 212 General and administrative — 68 22 — 90 Restructuring and other termination costs — 30 3 — 33 Oil, natural gas and NGL depreciation, depletion and amortization — 615 36 10 661 Depreciation and amortization of other assets — 38 71 (30 ) 79 Impairment of oil and natural gas — — 38 (38 ) — Impairments of fixed assets and other — 37 3 — 40 Net losses on sales of fixed assets — (85 ) (8 ) — (93 ) Total Operating Expenses — 4,233 552 (243 ) 4,542 INCOME FROM OPERATIONS — 574 36 — 610 OTHER INCOME (EXPENSE): Interest expense (156 ) (3 ) (20 ) 152 (27 ) Losses on investments — (19 ) (5 ) — (24 ) Losses on purchases of debt (195 ) — — — (195 ) Other income 136 29 — (158 ) 7 Equity in net earnings (losses) of subsidiary 324 (32 ) — (292 ) — Total Other Income (Expense) 109 (25 ) (25 ) (298 ) (239 ) INCOME BEFORE INCOME TAXES 109 549 11 (298 ) 371 INCOME TAX EXPENSE (BENEFIT) (82 ) 221 4 (2 ) 141 NET INCOME 191 328 7 (296 ) 230 Net income attributable to noncontrolling interests — — — (39 ) (39 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 191 328 7 (335 ) 191 Other comprehensive income (loss) 1 (2 ) — — (1 ) COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 192 $ 326 $ 7 $ (335 ) $ 190 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS SIX MONTHS ENDED JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,729 $ 84 $ — $ 1,813 Marketing, gathering and compression — 3,980 — — 3,980 Total Revenues — 5,709 84 — 5,793 OPERATING EXPENSES: Oil, natural gas and NGL production — 554 21 — 575 Production taxes — 60 2 — 62 Marketing, gathering and compression — 3,796 — — 3,796 General and administrative 1 121 3 — 125 Restructuring and other termination costs — (14 ) — — (14 ) Provision for legal contingencies 339 20 — — 359 Oil, natural gas and NGL depreciation, depletion and amortization — 1,249 55 (19 ) 1,285 Depreciation and amortization of other assets — 69 — — 69 Impairment of oil and natural gas properties — 9,983 406 (398 ) 9,991 Impairments of fixed assets and other — 88 — — 88 Net losses on sales of fixed assets — 4 — — 4 Total Operating Expenses 340 15,930 487 (417 ) 16,340 LOSS FROM OPERATIONS (340 ) (10,221 ) (403 ) 417 (10,547 ) OTHER INCOME (EXPENSE): Interest expense (351 ) (74 ) — 303 (122 ) Losses on investments — (24 ) — — (24 ) Other income (expense) (39 ) 7 — 37 5 Equity in net earnings (losses) of subsidiary (7,314 ) (333 ) — 7,647 — Total Other Expense (7,704 ) (424 ) — 7,987 (141 ) LOSS BEFORE INCOME TAXES (8,044 ) (10,645 ) (403 ) 8,404 (10,688 ) INCOME TAX BENEFIT (197 ) (2,778 ) (107 ) 204 (2,878 ) NET LOSS (7,847 ) (7,867 ) (296 ) 8,200 (7,810 ) Net income attributable to noncontrolling interests — — — (37 ) (37 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (7,847 ) (7,867 ) (296 ) 8,163 (7,847 ) Other comprehensive income (loss) (2 ) 14 — — 12 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (7,849 ) $ (7,853 ) $ (296 ) $ 8,163 $ (7,835 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS SIX MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,282 $ 192 $ (3 ) $ 3,471 Marketing, gathering and compression — 6,180 2 — 6,182 Oilfield services — 40 983 (478 ) 545 Total Revenues — 9,502 1,177 (481 ) 10,198 OPERATING EXPENSES: Oil, natural gas and NGL production — 549 21 — 570 Production taxes — 119 3 — 122 Marketing, gathering and compression — 6,145 2 — 6,147 Oilfield services — 54 769 (392 ) 431 General and administrative — 124 45 — 169 Restructuring and other termination costs — 23 3 — 26 Oil, natural gas and NGL depreciation, depletion and amortization — 1,201 79 8 1,288 Depreciation and amortization of other assets — 78 143 (64 ) 157 Impairment of oil and natural gas — — 98 (98 ) — Impairments of fixed assets and other — 37 23 — 60 Net gains on sales of fixed assets — (109 ) (6 ) — (115 ) Total Operating Expenses — 8,221 1,180 (546 ) 8,855 INCOME (LOSS) FROM OPERATIONS — 1,281 (3 ) 65 1,343 OTHER INCOME (EXPENSE): Interest expense (347 ) (3 ) (42 ) 326 (66 ) Losses on investments — (42 ) (5 ) 2 (45 ) Net gain on sales of investments — 67 — — 67 Losses on purchases of debt (195 ) — — — (195 ) Other income (expense) 479 (114 ) 1 (353 ) 13 Equity in net earnings (losses) of subsidiary 655 (111 ) — (544 ) — Total Other Income (Expense) 592 (203 ) (46 ) (569 ) (226 ) INCOME (LOSS) BEFORE INCOME TAXES 592 1,078 (49 ) (504 ) 1,117 INCOME TAX EXPENSE (BENEFIT) (24 ) 448 (18 ) 15 421 NET INCOME (LOSS) 616 630 (31 ) (519 ) 696 Net income attributable to noncontrolling interests — — — (80 ) (80 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 616 630 (31 ) (599 ) 616 Other comprehensive income 3 5 — — 8 COMPREHENSIVE INCOME (LOSS) $ 619 $ 635 $ (31 ) $ (599 ) $ 624 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS SIX MONTHS ENDED JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 638 $ 99 $ — $ 737 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,077 ) (91 ) — (2,168 ) Acquisitions of proved and unproved properties — (266 ) — — (266 ) Proceeds from divestitures of proved and unproved properties — 14 — — 14 Additions to other property and equipment — (93 ) — — (93 ) Other investing activities — (2 ) 3 — 1 Net Cash Used In Investing Activities — (2,424 ) (88 ) — (2,512 ) CASH FLOWS FROM FINANCING ACTIVITIES: Other financing activities (565 ) 398 (65 ) (50 ) (282 ) Intercompany advances, net (1,387 ) 1,387 — — — Net Cash Used In Financing Activities (1,952 ) 1,785 (65 ) (50 ) (282 ) Net decrease in cash and cash equivalents (1,952 ) (1 ) (54 ) (50 ) (2,057 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 2,148 $ 1 $ 30 $ (128 ) $ 2,051 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS SIX MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 2,337 $ 306 $ — $ 2,643 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,946 ) (50 ) — (1,996 ) Acquisitions of proved and unproved properties — (354 ) (2 ) — (356 ) Proceeds from divestitures of proved and unproved properties — 247 1 — 248 Additions to other property and equipment — (368 ) (252 ) — (620 ) Other investing activities — 877 60 7 944 Net Cash Used In Investing Activities — (1,544 ) (243 ) 7 (1,780 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 140 717 — 857 Payments on credit facilities borrowings — (140 ) (1,099 ) — (1,239 ) 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 (193 ) (29 ) (94 ) (32 ) (348 ) Intercompany advances, net 1,186 (764 ) (422 ) — — Net Cash Provided By (Used In) Financing Activities 597 (793 ) (10 ) (32 ) (238 ) Net increase in cash and cash equivalents 597 — 53 (25 ) 625 Cash and cash equivalents, beginning of period 799 — 38 — 837 Cash and cash equivalents, end of period $ 1,396 $ — $ 91 $ (25 ) $ 1,462

Recently Issued Accounting Stan

Recently Issued Accounting Standards (Note)	6 Months Ended
	Jun. 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 condensed 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 condensed consolidated financial statements.

Basis of Presentation and Sum29

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	6 Months Ended
	Jun. 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 six months ended June 30, 2015 (the "Current Quarter" and the “Current Period”, respectively) and the three and six months ended June 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)	6 Months Ended
	Jun. 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)	6 Months Ended
	Jun. 30, 2015
Asset Impairment Charges [Abstract]
Impairment or Disposal of Long-Lived Assets, Policy	Our oil and natural gas properties are subject to quarterly full cost ceiling tests.

Income Taxes (Policy)

Income Taxes (Policy)	6 Months Ended
	Jun. 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 St33

Recently Issued Accounting Standards (Policies)	6 Months Ended
	Jun. 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 condensed 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 condensed consolidated financial statements.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 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 June 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 Participating securities $ — 1 Three Months Ended June 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 22 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 Net Income Adjustments Shares ($ in millions) (in millions) Six Months Ended June 30, 2015 Common stock equivalent of our preferred stock outstanding: 5.75% cumulative convertible preferred stock $ 43 59 5.75% cumulative convertible preferred stock (series A) $ 32 42 5.00% cumulative convertible preferred stock (series 2005B) $ 5 6 4.50% cumulative convertible preferred stock $ 6 6 Participating securities $ — 2 Six Months Ended June 30, 2014 Common stock equivalent of our preferred stock outstanding: 5.00% cumulative convertible preferred stock (series 2005B) $ 5 6 4.50% cumulative convertible preferred stock $ 6 6 Participating securities $ 11 3
Schedule of Earnings Per Share, Basic and Diluted	A reconciliation of basic EPS and diluted EPS for the Prior Period is as follows: Income (Numerator) Weighted Average Shares (Denominator) Per Share Amount (in millions, except per share data) Six Months Ended June 30, 2014 Basic EPS $ 518 658 $ 0.79 Effect of Dilutive Securities: Assumed conversion as of the beginning of the period of preferred shares outstanding during the period: Common shares assumed issued for 5.75% cumulative convertible preferred stock 43 59 Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A) 32 42 Outstanding stock options — 1 Diluted EPS $ 593 760 $ 0.78

Debt (Tables)

Debt (Tables)	6 Months Ended
	Jun. 30, 2015
Debt Disclosure [Abstract]
Schedule of Debt	Our long-term debt consisted of the following as of June 30, 2015 and December 31, 2014: June 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) (188 ) (231 ) Interest rate derivatives (d) 8 10 Total debt, net 11,544 11,535 Less current maturities of long-term debt, net (e) (889 ) (381 ) Total long-term debt, net $ 10,655 $ 11,154 ___________________________________________ (a) The principal amount shown is based on the exchange rate of $1.1147 to €1.00 and $1.2098 to €1.00 as of June 30, 2015 and December 31, 2014, respectively. See 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 holders of our 2.75% Contingent Convertible Senior Notes due 2035 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. 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 second 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 third 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. (c) Discount as of June 30, 2015 and December 31, 2014 included $181 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 Note 8 for further discussion related to these instruments. (e) As of June 30, 2015 , current maturities of long-term debt, net includes the carrying amount of our 3.25% Senior Notes due March 2016 and 2.75% Contingent Convertible Senior Notes due 2035. As discussed in footnote (b) above, the holders of our 2.75% Contingent Convertible Senior Notes due 2035 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 June 30, 2015 and December 31, 2014, current maturities of long-term debt, net reflects $7 million and $15 million , respectively, of discount associated with the equity component of the 2.75% Contingent Convertible Senior Notes due 2035.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below. June 30, 2015 December 31, 2014 Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value ($ in millions) Short-term debt (Level 1) $ 889 $ 892 $ 381 $ 396 Long-term debt (Level 1) $ 10,647 $ 10,286 $ 11,144 $ 11,656

Contingencies and Commitments36

Contingencies and Commitments (Tables)	6 Months Ended
	Jun. 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 discussed above, are presented below. June 30, ($ in millions) 2015 $ 914 2016 1,936 2017 1,941 2018 1,723 2019 1,437 2020 – 2099 6,227 Total $ 14,178

Other Liabilities (Tables)

Other Liabilities (Tables)	6 Months Ended
	Jun. 30, 2015
Other Liabilities Disclosure [Abstract]
Other Current Liabilities	Other current liabilities as of June 30, 2015 and December 31, 2014 are detailed below. June 30, December 31, ($ in millions) Revenues and royalties due others $ 757 $ 1,176 Accrued drilling and production costs 327 385 Joint interest prepayments received 202 189 Accrued compensation and benefits 237 344 Other accrued taxes 130 55 Accrued dividends 43 101 Bank of New York Mellon legal accrual 439 100 Oklahoma royalty settlement 114 119 Other 400 592 Total other current liabilities $ 2,649 $ 3,061
Other Long-Term Liabilities	Other long-term liabilities as of June 30, 2015 and December 31, 2014 are detailed below. June 30, December 31, ($ in millions) CHK Utica ORRI conveyance obligation (a) $ 205 $ 220 CHK C-T ORRI conveyance obligation (b) 128 135 Financing obligations 29 30 Unrecognized tax benefits 46 45 Other 141 249 Total other long-term liabilities $ 549 $ 679 ____________________________________________ (a) $20 million and $14 million of the total $225 million and $234 million obligations are recorded in other current liabilities as of June 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation. (b) $28 million and $23 million of the total $156 million and $158 million obligations are recorded in other current liabilities as of June 30, 2015 and December 31, 2014, respectively. See Noncontrolling Interests in Note 6 for further discussion of the conveyance obligation.

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 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: Six 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) 103 (2,019 ) Stock option exercises 14 1,268 Shares issued as of June 30 665,061 665,441 ___________________________________________ (a) In the second quarter of 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors and employees. Shares of common stock underlying RSUs are issued when the units vest, whereas shares of common stock were previously issued on the date the RSAs were granted. We refer to RSAs and RSUs collectively as restricted stock.
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 June 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 (1 ) — (1 ) Amounts reclassified from accumulated other comprehensive income 13 — 13 Net other comprehensive income 12 — 12 Balance, June 30, 2015 $ (131 ) $ — $ (131 ) Balance, December 31, 2013 $ (167 ) $ 5 $ (162 ) Other comprehensive income before reclassifications 3 — 3 Amounts reclassified from accumulated other comprehensive income 10 (5 ) 5 Net other comprehensive income 13 (5 ) 8 Balance, June 30, 2014 $ (154 ) $ — $ (154 )
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 June 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 3 Total reclassifications for the period, net of tax $ 3 Three Months Ended June 30, 2014 Net gains on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ (1 ) Total reclassifications for the period, net of tax $ (1 ) Six Months Ended June 30, 2015 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 13 Total reclassifications for the period, net of tax $ 13 Six Months Ended June 30, 2014 Net losses on cash flow hedges: Commodity contracts Oil, natural gas and NGL revenues $ 10 Investments: Sale of investment Net gain on sale of investment (5 ) Total reclassifications for the period, net of tax $ 5
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 December 2014 – February 2015 June 1, 2015 $ 0.3899 $ — September 2014 – November 2014 March 2, 2015 $ 0.4496 $ — 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)	6 Months Ended
	Jun. 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 6,918 $ 14.03 Vested (2,651 ) $ 16.79 Forfeited (374 ) $ 15.28 Unvested restricted stock as of June 30, 2015 13,984 $ 18.65
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 40.12 % Risk-free interest rate 0.95 % Dividend yield for value of awards 1.91 %
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 June 30, 2015 5,580 $ 19.33 6.39 $ — Exercisable at June 30, 2015 2,169 $ 19.44 5.59 $ — ___________________________________________ (a) The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
Equity-Classified Stock-Based Compensation	We recognized the following compensation costs (credits) related to PSUs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period: Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (4 ) $ 11 $ (14 ) $ 10 Restructuring and other termination costs (5 ) 15 (15 ) 6 Marketing, gathering and compression — 1 (1 ) 1 Oil and natural gas properties — 2 (1 ) 3 Total $ (9 ) $ 29 $ (31 ) $ 20 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 12 $ 11 $ 24 $ 24 Oil and natural gas properties 8 9 15 16 Oil, natural gas and NGL production expenses 6 5 10 8 Marketing, gathering and compression expenses 2 1 3 3 Oilfield services expenses — 3 — 5 Total $ 28 $ 29 $ 52 $ 56
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 40.12 % Risk-free interest rate 0.95 % Dividend yield for value of awards 1.91 %
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 $ 13 $ 12 2014 Awards: Payable 2017 609,637 $ 16 $ 1 $ 1 2015 Awards: Payable 2018 696,683 $ 13 $ 5 $ 2 ___________________________________________ (a) As of June 30, 2015 .
Liability-Classified Stock-Based 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ (4 ) $ 11 $ (14 ) $ 10 Restructuring and other termination costs (5 ) 15 (15 ) 6 Marketing, gathering and compression — 1 (1 ) 1 Oil and natural gas properties — 2 (1 ) 3 Total $ (9 ) $ 29 $ (31 ) $ 20 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) General and administrative expenses $ 12 $ 11 $ 24 $ 24 Oil and natural gas properties 8 9 15 16 Oil, natural gas and NGL production expenses 6 5 10 8 Marketing, gathering and compression expenses 2 1 3 3 Oilfield services expenses — 3 — 5 Total $ 28 $ 29 $ 52 $ 56

Derivative and Hedging Activi40

Derivative and Hedging Activities (Tables)	6 Months Ended
	Jun. 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 June 30, 2015 and December 31, 2014 are provided below. June 30, 2015 December 31, 2014 Volume Fair Value Volume Fair Value ($ in millions) ($ in millions) Oil (mmbbl): Fixed-price swaps 7.4 $ 196 12.5 $ 471 Three-way collars 2.2 21 4.4 40 Call options 27.9 (26 ) 35.8 (89 ) Basis protection swaps 4.5 4 — — Total oil 42.0 $ 195 52.7 $ 422 Natural gas (tbtu): Fixed-price swaps 260 $ 135 275 $ 281 Three-way collars 71 51 207 165 Call options 193 (128 ) 193 (170 ) Basis protection swaps 80 5 60 23 Total natural gas 604 $ 63 735 $ 299 Total estimated fair value $ 258 $ 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 June 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 June 30, 2015 Commodity Contracts: Short-term derivative asset $ 426 $ (74 ) $ 352 Short-term derivative liability (101 ) 74 (27 ) Long-term derivative liability (67 ) — (67 ) Total commodity contracts 258 — 258 Interest Rate Contracts: Short-term derivative liability — — — Total interest rate contracts — — — Foreign Currency Contracts: (a) Long-term derivative liability (88 ) — (88 ) Total foreign currency contracts (88 ) — (88 ) Supply Contracts: Short-term derivative asset 35 — 35 Long-term derivative asset 186 — 186 Total supply contracts 221 — 221 Total derivatives $ 391 $ — $ 391 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 sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression sales (a) $ 2,085 $ 3,167 $ 3,760 $ 6,182 Gains on undesignated supply contract derivatives 220 — 220 — Total marketing, gathering and compression sales $ 2,305 $ 3,167 $ 3,980 $ 6,182 ____________________________________________ (a) Current Quarter and Current Period settlements of $27 million on supply contracts accounted for as derivatives are reflected in marketing, gathering and compression revenues. The components of oil, natural gas and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 776 $ 1,917 $ 1,700 $ 4,065 Gains (losses) on undesignated oil and natural gas derivatives (43 ) (210 ) 135 (574 ) Losses on terminated cash flow hedges (5 ) (3 ) (22 ) (20 ) Total oil, natural gas and NGL sales $ 728 $ 1,704 $ 1,813 $ 3,471
Schedule of Derivative Instruments, Marketing, Gathering and Compression Sales	The components of marketing, gathering and compression sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Marketing, gathering and compression sales (a) $ 2,085 $ 3,167 $ 3,760 $ 6,182 Gains on undesignated supply contract derivatives 220 — 220 — Total marketing, gathering and compression sales $ 2,305 $ 3,167 $ 3,980 $ 6,182 ____________________________________________ (a) Current Quarter and Current Period settlements of $27 million on supply contracts accounted for as derivatives are reflected in marketing, gathering and compression revenues. The components of oil, natural gas and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below. Three Months Ended Six Months Ended 2015 2014 2015 2014 ($ in millions) Oil, natural gas and NGL sales $ 776 $ 1,917 $ 1,700 $ 4,065 Gains (losses) on undesignated oil and natural gas derivatives (43 ) (210 ) 135 (574 ) Losses on terminated cash flow hedges (5 ) (3 ) (22 ) (20 ) Total oil, natural gas and NGL sales $ 728 $ 1,704 $ 1,813 $ 3,471
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 Six Months Ended 2015 2014 2015 2014 ($ in millions) Interest expense on senior notes $ 171 $ 184 $ 342 $ 364 Interest expense on term loan — 7 — 36 Amortization of loan discount, issuance costs and other 12 16 23 35 Interest expense on credit facilities 3 9 6 17 Gains on terminated fair value hedges (1 ) (1 ) (2 ) (2 ) Gains on undesignated interest rate derivatives — (33 ) (10 ) (51 ) Capitalized interest (114 ) (155 ) (237 ) (333 ) Total interest expense $ 71 $ 27 $ 122 $ 66
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 June 30, 2015 2014 Before Tax After Tax Before Tax After Tax ($ in millions) Balance, beginning of period $ (216 ) $ (134 ) $ (247 ) $ (153 ) Net change in fair value — — 1 — (Gains) losses reclassified to income 5 3 3 (1 ) Balance, end of period $ (211 ) $ (131 ) $ (243 ) $ (154 ) Six Months Ended June 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 (2 ) (1 ) 6 3 Losses reclassified to income 22 13 20 10 Balance, end of period $ (211 ) $ (131 ) $ (243 ) $ (154 )
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 June 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 June 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 353 $ 73 $ 426 Commodity liabilities — (13 ) (155 ) (168 ) Interest rate liabilities — — — — Foreign currency liabilities — (88 ) — (88 ) Supply contract assets — — 221 221 Total derivatives $ — $ 252 $ 139 $ 391 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 June 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 June 30, 2015 Financial Assets (Liabilities): Other current assets $ 62 $ — $ — $ 62 Other current liabilities (63 ) — — (63 ) Total $ (1 ) $ — $ — $ (1 ) As of December 31, 2014 Financial Assets (Liabilities): Other current assets $ 57 $ — $ — $ 57 Other current liabilities (58 ) — — (58 ) Total $ (1 ) $ — $ — $ (1 )
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation	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) (realized/unrealized): Included in earnings (a) 80 220 Total purchases, issuances, sales and settlements: Settlements (108 ) — Ending balance as of June 30, 2015 $ (82 ) $ 221 Beginning balance as of January 1, 2014 $ (478 ) $ — Total gains (losses) (realized/unrealized): Included in earnings (a) (173 ) — Total purchases, issuances, sales and settlements: Settlements 105 — Transfers (b) (4 ) — Ending balance as of June 30, 2014 $ (550 ) $ — ___________________________________________ (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 $ 80 $ (173 ) $ 220 $ — Change in unrealized gains (losses) related to assets still held at reporting date $ 69 $ (133 ) $ 220 $ — (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 June 30, 2015 : Instrument Type Unobservable Input Range Weighted Average Fair Value June 30, 2015 ($ in millions) Oil trades (a) Oil price volatility curves 19.51% – 32.31% 26.97% $ (5 ) Supply contracts (b) Oil price volatility curves 16.55% – 33.27% 20.05% $ 221 Natural gas trades (a) Natural gas price volatility curves 20.47% – 56.46% 32.19% $ (77 ) ___________________________________________ (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 41

Oil and Natural Gas Property Transactions (Tables)	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment [Abstract]
VPP Transactions	As of June 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 8 September 2010 Barnett Shale 1,150 — 390 — 390 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 $ 5,481 5.2 1,105 14.0 1,220
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 June 30, 2015 Three Months Ended June 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 78.0 2.2 268.7 4.3 103.0 2.7 329.9 5.3 9 42.5 3.5 94.9 4.4 47.5 3.9 103.9 4.8 8 — 13.6 — 13.6 — 15.2 — 15.2 6 (a) — — — — 6.0 1.1 — 1.1 5 (a) — — — — 6.0 1.7 — 1.7 4 10.7 2.0 — 2.1 12.2 2.3 — 2.3 3 — 1.6 — 1.6 — 1.8 — 1.8 2 — 1.0 — 1.0 — 1.6 — 1.6 1 — 3.3 — 3.3 — 3.4 — 3.4 131.2 27.2 363.6 30.3 174.7 33.7 433.8 37.2 Six Months Ended June 30, 2015 Six Months Ended June 30, 2014 VPP # Oil Natural Gas NGL Total Oil Natural Gas NGL Total (mbbl) (bcf) (mbbl) (bcfe) (mbbl) (bcf) (mbbl) (bcfe) 10 161.0 4.4 545.0 8.7 212.0 5.5 675.1 10.8 9 86.1 7.2 191.9 8.9 96.5 7.9 210.4 9.7 8 — 27.6 — 27.6 — 30.9 — 30.9 6 (a) — — — — 12.0 2.2 — 2.3 5 (a) — — — — 12.3 3.4 — 3.5 4 21.7 4.1 — 4.2 24.6 4.6 — 4.7 3 — 3.3 — 3.3 — 3.7 — 3.7 2 — 2.1 — 2.1 — 4.0 — 4.0 1 — 6.8 — 6.8 — 7.0 — 7.0 268.8 55.5 736.9 61.6 357.4 69.2 885.5 76.6 ____________________________________________ (a) 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 June 30, 2015 were as follows: Volume Remaining as of June 30, 2015 VPP # Term Remaining Oil Natural Gas NGL Total (in months) (mmbbl) (bcf) (mmbbl) (bcfe) 10 80 1.2 33.6 4.1 65.4 9 68 0.7 66.0 1.7 81.0 8 2 — 8.9 — 8.9 4 18 0.1 11.2 — 11.6 3 49 — 20.6 — 20.6 2 46 — 11.7 — 11.7 1 90 — 84.8 — 84.8 2.0 236.8 5.8 284.0

Investments (Tables)

Investments (Tables)	6 Months Ended
	Jun. 30, 2015
Investments [Abstract]
Equity Method Investments	A summary of our investments, including our approximate ownership percentage and carrying value as of June 30, 2015 and December 31, 2014 , is presented below. Approximate Ownership % Carrying Value Accounting Method June 30, December 31, June 30, December 31, ($ in millions) FTS International, Inc. Equity 30% 30% $ 106 $ 116 Sundrop Fuels, Inc. Equity 56% 56% 131 130 Other — —% —% 18 19 Total investments $ 255 $ 265

Other Property and Equipment (T

Other Property and Equipment (Tables)	6 Months Ended
	Jun. 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 Six Months Ended 2015 2014 2015 2014 ($ in millions) Natural gas compressors $ — $ (94 ) $ — $ (120 ) Gathering systems and treating plants — 10 — 13 Oilfield services equipment — (9 ) — (7 ) Buildings and land — 1 1 1 Other 1 (1 ) 3 (2 ) Total net (gains) losses on sales of fixed assets $ 1 $ (93 ) $ 4 $ (115 )

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 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 June 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 June 30, 2015 Derivative Assets (Liabilities): Commodity assets $ — $ 353 $ 73 $ 426 Commodity liabilities — (13 ) (155 ) (168 ) Interest rate liabilities — — — — Foreign currency liabilities — (88 ) — (88 ) Supply contract assets — — 221 221 Total derivatives $ — $ 252 $ 139 $ 391 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 June 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 June 30, 2015 Financial Assets (Liabilities): Other current assets $ 62 $ — $ — $ 62 Other current liabilities (63 ) — — (63 ) Total $ (1 ) $ — $ — $ (1 ) 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)	6 Months Ended
	Jun. 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 June 30, 2015 Revenues $ 699 $ 3,509 $ — $ — $ (1,175 ) $ 3,033 Intersegment revenues 29 (1,204 ) — — 1,175 — Total revenues $ 728 $ 2,305 $ — $ — $ — $ 3,033 Income (Loss) Before Income Taxes $ (5,785 ) $ 134 $ — $ (31 ) $ 86 $ (5,596 ) Three Months Ended June 30, 2014 Revenues $ 1,704 $ 5,355 $ 552 $ 3 $ (2,462 ) $ 5,152 Intersegment revenues — (2,188 ) (274 ) — 2,462 — Total revenues $ 1,704 $ 3,167 $ 278 $ 3 $ — $ 5,152 Income (Loss) Before Income Taxes $ 410 $ 109 $ 19 $ (20 ) $ (147 ) $ 371 Six Months Ended June 30, 2015 Revenues $ 1,761 $ 6,417 $ — $ — $ (2,385 ) $ 5,793 Intersegment revenues 52 (2,437 ) — — 2,385 — Total revenues $ 1,813 $ 3,980 $ — $ — $ — $ 5,793 Income (Loss) Before Income Taxes $ (11,134 ) $ 138 $ — $ (45 ) $ 353 $ (10,688 ) Six Months Ended June 30, 2014 Revenues $ 3,471 $ 10,777 $ 1,060 $ 30 $ (5,140 ) $ 10,198 Intersegment revenues — (4,596 ) (544 ) — 5,140 — Total revenues $ 3,471 $ 6,181 $ 516 $ 30 $ — $ 10,198 Income (Loss) Before Income Taxes $ 1,098 $ 213 $ (16 ) $ 39 $ (217 ) $ 1,117 As of June 30, 2015 Total Assets $ 22,815 $ 1,946 $ — $ 4,364 $ (527 ) $ 28,598 As of December 31, 2014 Total Assets $ 35,381 $ 1,978 $ — $ 4,283 $ (891 ) $ 40,751

Condensed Consolidating Finan46

Condensed Consolidating Financial Information (Tables)	6 Months Ended
	Jun. 30, 2015
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule of Condensed Balance Sheet	CONDENSED CONSOLIDATING BALANCE SHEET AS OF JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non-Guarantor Subsidiaries Eliminations Consolidated CURRENT ASSETS: Cash and cash equivalents $ 2,148 $ 1 $ 30 $ (128 ) $ 2,051 Restricted cash — — 38 — 38 Other 78 2,013 51 — 2,142 Intercompany receivable, net 24,917 — 365 (25,282 ) — Total Current Assets 27,143 2,014 484 (25,410 ) 4,231 PROPERTY AND EQUIPMENT: Oil and natural gas properties, at cost based on full cost accounting, net — 19,478 716 1,090 21,284 Other property and equipment, net — 2,237 1 — 2,238 Property and equipment held for sale, net — 93 — — 93 Total Property and Equipment, Net — 21,808 717 1,090 23,615 LONG-TERM ASSETS: Other assets 121 614 27 (10 ) 752 Investments in subsidiaries and intercompany advances (5,967 ) 188 — 5,779 — TOTAL ASSETS $ 21,297 $ 24,624 $ 1,228 $ (18,551 ) $ 28,598 CURRENT LIABILITIES: Current liabilities $ 1,547 $ 3,653 $ 56 $ (128 ) $ 5,128 Intercompany payable, net — 24,785 — (24,785 ) — Total Current Liabilities 1,547 28,438 56 (24,913 ) 5,128 LONG-TERM LIABILITIES: Long-term debt, net 10,655 — — — 10,655 Deferred income tax liabilities — 1,263 78 67 1,408 Other long-term liabilities 137 890 137 — 1,164 Total Long-Term Liabilities 10,792 2,153 215 67 13,227 EQUITY: Chesapeake stockholders’ equity 8,958 (5,967 ) 957 5,010 8,958 Noncontrolling interests — — — 1,285 1,285 Total Equity 8,958 (5,967 ) 957 6,295 10,243 TOTAL LIABILITIES AND EQUITY $ 21,297 $ 24,624 $ 1,228 $ (18,551 ) $ 28,598 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 JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 693 $ 35 $ — $ 728 Marketing, gathering and compression — 2,305 — — 2,305 Total Revenues — 2,998 35 — 3,033 OPERATING EXPENSES: Oil, natural gas and NGL production — 267 9 — 276 Production taxes — 33 1 — 34 Marketing, gathering and compression — 2,096 — — 2,096 General and administrative — 67 2 — 69 Restructuring and other termination costs — (4 ) — — (4 ) Provision for legal contingencies 339 (5 ) — — 334 Oil, natural gas and NGL depreciation, depletion and amortization — 586 23 (8 ) 601 Depreciation and amortization of other assets — 34 — — 34 Impairment of oil and natural gas properties — 5,012 186 (183 ) 5,015 Impairments of fixed assets and other — 84 — — 84 Net losses on sales of fixed assets — 1 — — 1 Total Operating Expenses 339 8,171 221 (191 ) 8,540 LOSS FROM OPERATIONS (339 ) (5,173 ) (186 ) 191 (5,507 ) OTHER INCOME (EXPENSE): Interest expense (180 ) (37 ) — 146 (71 ) Losses on investments — (17 ) — — (17 ) Other income (expense) 81 (7 ) — (75 ) (1 ) Equity in net earnings (losses) of subsidiary (3,792 ) (154 ) — 3,946 — Total Other Expense (3,891 ) (215 ) — 4,017 (89 ) LOSS BEFORE INCOME TAXES (4,230 ) (5,388 ) (186 ) 4,208 (5,596 ) INCOME TAX BENEFIT (122 ) (1,404 ) (50 ) 70 (1,506 ) NET LOSS (4,108 ) (3,984 ) (136 ) 4,138 (4,090 ) Net income attributable to noncontrolling interests — — — (18 ) (18 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (4,108 ) (3,984 ) (136 ) 4,120 (4,108 ) Other comprehensive income — 3 — — 3 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (4,108 ) $ (3,981 ) $ (136 ) $ 4,120 $ (4,105 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS THREE MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,618 $ 88 $ (2 ) $ 1,704 Marketing, gathering and compression — 3,166 1 — 3,167 Oilfield services — 23 499 (241 ) 281 Total Revenues — 4,807 588 (243 ) 5,152 OPERATING EXPENSES: Oil, natural gas and NGL production — 272 10 — 282 Production taxes — 70 2 — 72 Marketing, gathering and compression — 3,166 — — 3,166 Oilfield services — 22 375 (185 ) 212 General and administrative — 68 22 — 90 Restructuring and other termination costs — 30 3 — 33 Oil, natural gas and NGL depreciation, depletion and amortization — 615 36 10 661 Depreciation and amortization of other assets — 38 71 (30 ) 79 Impairment of oil and natural gas — — 38 (38 ) — Impairments of fixed assets and other — 37 3 — 40 Net losses on sales of fixed assets — (85 ) (8 ) — (93 ) Total Operating Expenses — 4,233 552 (243 ) 4,542 INCOME FROM OPERATIONS — 574 36 — 610 OTHER INCOME (EXPENSE): Interest expense (156 ) (3 ) (20 ) 152 (27 ) Losses on investments — (19 ) (5 ) — (24 ) Losses on purchases of debt (195 ) — — — (195 ) Other income 136 29 — (158 ) 7 Equity in net earnings (losses) of subsidiary 324 (32 ) — (292 ) — Total Other Income (Expense) 109 (25 ) (25 ) (298 ) (239 ) INCOME BEFORE INCOME TAXES 109 549 11 (298 ) 371 INCOME TAX EXPENSE (BENEFIT) (82 ) 221 4 (2 ) 141 NET INCOME 191 328 7 (296 ) 230 Net income attributable to noncontrolling interests — — — (39 ) (39 ) NET INCOME ATTRIBUTABLE TO CHESAPEAKE 191 328 7 (335 ) 191 Other comprehensive income (loss) 1 (2 ) — — (1 ) COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE $ 192 $ 326 $ 7 $ (335 ) $ 190 CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS SIX MONTHS ENDED JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 1,729 $ 84 $ — $ 1,813 Marketing, gathering and compression — 3,980 — — 3,980 Total Revenues — 5,709 84 — 5,793 OPERATING EXPENSES: Oil, natural gas and NGL production — 554 21 — 575 Production taxes — 60 2 — 62 Marketing, gathering and compression — 3,796 — — 3,796 General and administrative 1 121 3 — 125 Restructuring and other termination costs — (14 ) — — (14 ) Provision for legal contingencies 339 20 — — 359 Oil, natural gas and NGL depreciation, depletion and amortization — 1,249 55 (19 ) 1,285 Depreciation and amortization of other assets — 69 — — 69 Impairment of oil and natural gas properties — 9,983 406 (398 ) 9,991 Impairments of fixed assets and other — 88 — — 88 Net losses on sales of fixed assets — 4 — — 4 Total Operating Expenses 340 15,930 487 (417 ) 16,340 LOSS FROM OPERATIONS (340 ) (10,221 ) (403 ) 417 (10,547 ) OTHER INCOME (EXPENSE): Interest expense (351 ) (74 ) — 303 (122 ) Losses on investments — (24 ) — — (24 ) Other income (expense) (39 ) 7 — 37 5 Equity in net earnings (losses) of subsidiary (7,314 ) (333 ) — 7,647 — Total Other Expense (7,704 ) (424 ) — 7,987 (141 ) LOSS BEFORE INCOME TAXES (8,044 ) (10,645 ) (403 ) 8,404 (10,688 ) INCOME TAX BENEFIT (197 ) (2,778 ) (107 ) 204 (2,878 ) NET LOSS (7,847 ) (7,867 ) (296 ) 8,200 (7,810 ) Net income attributable to noncontrolling interests — — — (37 ) (37 ) NET LOSS ATTRIBUTABLE TO CHESAPEAKE (7,847 ) (7,867 ) (296 ) 8,163 (7,847 ) Other comprehensive income (loss) (2 ) 14 — — 12 COMPREHENSIVE LOSS ATTRIBUTABLE TO CHESAPEAKE $ (7,849 ) $ (7,853 ) $ (296 ) $ 8,163 $ (7,835 ) CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS SIX MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated REVENUES: Oil, natural gas and NGL $ — $ 3,282 $ 192 $ (3 ) $ 3,471 Marketing, gathering and compression — 6,180 2 — 6,182 Oilfield services — 40 983 (478 ) 545 Total Revenues — 9,502 1,177 (481 ) 10,198 OPERATING EXPENSES: Oil, natural gas and NGL production — 549 21 — 570 Production taxes — 119 3 — 122 Marketing, gathering and compression — 6,145 2 — 6,147 Oilfield services — 54 769 (392 ) 431 General and administrative — 124 45 — 169 Restructuring and other termination costs — 23 3 — 26 Oil, natural gas and NGL depreciation, depletion and amortization — 1,201 79 8 1,288 Depreciation and amortization of other assets — 78 143 (64 ) 157 Impairment of oil and natural gas — — 98 (98 ) — Impairments of fixed assets and other — 37 23 — 60 Net gains on sales of fixed assets — (109 ) (6 ) — (115 ) Total Operating Expenses — 8,221 1,180 (546 ) 8,855 INCOME (LOSS) FROM OPERATIONS — 1,281 (3 ) 65 1,343 OTHER INCOME (EXPENSE): Interest expense (347 ) (3 ) (42 ) 326 (66 ) Losses on investments — (42 ) (5 ) 2 (45 ) Net gain on sales of investments — 67 — — 67 Losses on purchases of debt (195 ) — — — (195 ) Other income (expense) 479 (114 ) 1 (353 ) 13 Equity in net earnings (losses) of subsidiary 655 (111 ) — (544 ) — Total Other Income (Expense) 592 (203 ) (46 ) (569 ) (226 ) INCOME (LOSS) BEFORE INCOME TAXES 592 1,078 (49 ) (504 ) 1,117 INCOME TAX EXPENSE (BENEFIT) (24 ) 448 (18 ) 15 421 NET INCOME (LOSS) 616 630 (31 ) (519 ) 696 Net income attributable to noncontrolling interests — — — (80 ) (80 ) NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE 616 630 (31 ) (599 ) 616 Other comprehensive income 3 5 — — 8 COMPREHENSIVE INCOME (LOSS) $ 619 $ 635 $ (31 ) $ (599 ) $ 624
Schedule of Condensed Cash Flow Statement	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS SIX MONTHS ENDED JUNE 30, 2015 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 638 $ 99 $ — $ 737 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (2,077 ) (91 ) — (2,168 ) Acquisitions of proved and unproved properties — (266 ) — — (266 ) Proceeds from divestitures of proved and unproved properties — 14 — — 14 Additions to other property and equipment — (93 ) — — (93 ) Other investing activities — (2 ) 3 — 1 Net Cash Used In Investing Activities — (2,424 ) (88 ) — (2,512 ) CASH FLOWS FROM FINANCING ACTIVITIES: Other financing activities (565 ) 398 (65 ) (50 ) (282 ) Intercompany advances, net (1,387 ) 1,387 — — — Net Cash Used In Financing Activities (1,952 ) 1,785 (65 ) (50 ) (282 ) Net decrease in cash and cash equivalents (1,952 ) (1 ) (54 ) (50 ) (2,057 ) Cash and cash equivalents, beginning of period 4,100 2 84 (78 ) 4,108 Cash and cash equivalents, end of period $ 2,148 $ 1 $ 30 $ (128 ) $ 2,051 CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS SIX MONTHS ENDED JUNE 30, 2014 ($ in millions) Parent Guarantor Subsidiaries Non- Guarantor Subsidiaries Eliminations Consolidated CASH FLOWS FROM OPERATING ACTIVITIES: Net Cash Provided By Operating Activities $ — $ 2,337 $ 306 $ — $ 2,643 CASH FLOWS FROM INVESTING ACTIVITIES: Drilling and completion costs — (1,946 ) (50 ) — (1,996 ) Acquisitions of proved and unproved properties — (354 ) (2 ) — (356 ) Proceeds from divestitures of proved and unproved properties — 247 1 — 248 Additions to other property and equipment — (368 ) (252 ) — (620 ) Other investing activities — 877 60 7 944 Net Cash Used In Investing Activities — (1,544 ) (243 ) 7 (1,780 ) CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from credit facilities borrowings — 140 717 — 857 Payments on credit facilities borrowings — (140 ) (1,099 ) — (1,239 ) 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 (193 ) (29 ) (94 ) (32 ) (348 ) Intercompany advances, net 1,186 (764 ) (422 ) — — Net Cash Provided By (Used In) Financing Activities 597 (793 ) (10 ) (32 ) (238 ) Net increase in cash and cash equivalents 597 — 53 (25 ) 625 Cash and cash equivalents, beginning of period 799 — 38 — 837 Cash and cash equivalents, end of period $ 1,396 $ — $ 91 $ (25 ) $ 1,462

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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
5.75% Cumulative Convertible Preferred Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 21	$ 22	$ 43
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	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	$ 32
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	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	$ 5	$ 5
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	$ 6	$ 6
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	6	6
Restricted Stock [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net Income Adjustments	$ 0	$ 3	$ 0	$ 11
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	1	3	2	3

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share - Reconciliation of Basic and Diluted EPS Table (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Net Income (Loss) Available to Common Stockholders, Basic	$ (4,151)	$ 145	$ (7,933)	$ 518
Weighted Average Number of Shares Outstanding, Basic	662	659	662	658
Earnings Per Share, Basic	$ (6.27)	$ 0.22	$ (11.99)	$ 0.79
Net Income (Loss) Available to Common Stockholders, Diluted				$ 593
Weighted Average Number of Shares Outstanding, Diluted	662	659	662	760
Earnings Per Share, Diluted	$ (6.27)	$ 0.22	$ (11.99)	$ 0.78
Employee Stock Option [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities				$ 0
Weighted Average Number Diluted Shares Outstanding Adjustment				1
5.75% Cumulative Convertible Preferred Stock [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities				$ 43
Weighted Average Number Diluted Shares Outstanding Adjustment				59
5.75% Cumulative Convertible Preferred Stock Series A [Member]
Earnings Per Share Adjustments, Basic and Diluted [Line Items]
Dilutive Securities, Effect on Basic Earnings Per Share, Dilutive Convertible Securities				$ 32
Weighted Average Number Diluted Shares Outstanding Adjustment				42

Debt - Long-Term Debt Table (De

Debt - Long-Term Debt Table (Details) $ / shares in Units, $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)$ / shares$ / €	Dec. 31, 2014USD ($)$ / €	Dec. 31, 2006USD ($)$ / €
Long-Term Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	$ (188)	$ (231)
Long-term Debt	11,544	11,535
Current maturities of long-term debt, net	(889)	(381)
Long-term debt, net	$ 10,655	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	(181)	(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%
Debt Instrument, Convertible, Terms of Conversion Feature	5 days
Credit Facility Commitment Period	10 years
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]
Long-term Debt, Gross	$ 384
Derivative, Forward Exchange Rate | $ / €	1.1147	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]
Common Stock Price Conversion Thresholds | $ / shares	$ 45.14
Debt Instrument, Date of First Required Payment	May 14, 2016
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, Unamortized Discount	$ (7)	(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) - Jun. 30, 2015	Total
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	Jun. 30, 2015	Dec. 31, 2014
Senior Notes [Member]
Long-Term Debt Instrument [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent		100.00%
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
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%
6.775% Senior Notes Due 2019 [Member] | Senior Notes [Member] | Subsequent Event [Member]
Long-Term Debt Instrument [Line Items]
Loss Contingency, Damages Awarded, Value	$ 380
Loss Contingency, Prejudgment Interest Awarded	$ 59

Debt - Revolving Credit Facilit

Debt - Revolving Credit Facility Narrative (Details) - Jun. 30, 2015 - Revolving Credit Facility [Member] $ in Millions	USD ($)extension
Long-Term Debt Instrument [Line Items]
Commitment Period	5 years
Borrowing capacity	$ 4,000
Line of Credit Facility, Increase (Decrease), Net	$ 1,000
Debt Instrument Maturity Date	Dec. 15, 2019
Line of Credit Facility, Number of Expiration Period Options | extension	2
Line of Credit Facility, Expiration Period Option	1 year
Long-term Debt, Gross	$ 0
Letters of Credit Outstanding, Amount	$ 15
Interest Rate In Addition To Federal Funds Rate	0.50%
Loans Receivable, Basis Spread on Variable Rate	1.00%
Debt Instrument, Covenant Description	4.0 to 1.0
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
Alternative Base Rate (ABR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	0.625%
London Interbank Offered Rate (LIBOR) [Member]
Long-Term Debt Instrument [Line Items]
Line of Credit Facility, Interest Rate at Period End	1.625%
Maximum [Member]
Long-Term Debt Instrument [Line Items]
Ratio of Indebtedness to Net Capital	65
Moody's, Ba3 Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	Ba3
Standard & Poor's, BB- Rating [Member] | Minimum [Member]
Long-Term Debt Instrument [Line Items]
Debt Instrument, Credit Rating	BB-

Debt Debt - Spin-Off of Oilfiel

Debt Debt - Spin-Off of Oilfield Services Business (Details) - USD ($) $ in Millions	Jun. 30, 2014	Jun. 30, 2015	Jun. 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. Revolving Credit Facility [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Borrowing capacity	$ 275		275
Secured Debt [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Long-term Debt, Gross	400		400
6.5% Senior Notes Due 2022 [Member] | Senior Notes [Member] | Seven Seven Energy Inc. [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
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | Seven Seven Energy Inc. Revolving Credit Facility [Member] | Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Commitment Period			5 years
Borrowing capacity	275		$ 275
Payments of Financing Costs			$ 3
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | Secured Debt [Member] | Seven Seven Energy Inc. [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		$ 400
Proceeds from Issuance of Secured Debt			394
Disposal Group, Disposed of by Means Other than Sale, Not Discontinued Operations, Spinoff [Member] | 6.5% Senior Notes Due 2022 [Member] | Senior Notes [Member] | Seven Seven Energy Inc. [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%
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	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value of Debt	$ 11,544	$ 11,535
Short-term Debt [Member] | Reported Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value of Debt	889	381
Short-term Debt [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value of Debt	892	396
Long-term Debt [Member] | Reported Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value of Debt	10,647	11,144
Long-term Debt [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value of Debt	$ 10,286	$ 11,656

Contingencies - Narrative (Deta

Contingencies - Narrative (Details) $ in Millions	Apr. 24, 2015misdemeanor	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)
Loss Contingencies [Line Items]
Provision for legal contingencies		$ 334	$ 0	$ 359	$ 0
Michigan Antitrust [Member]
Loss Contingencies [Line Items]
Loss Contingency, Claims Settled, Number | misdemeanor	1
Michigan False Pretenses [Member]
Loss Contingencies [Line Items]
Loss Contingency, Claims Settled, Number | misdemeanor	1
Michigan Landowners [Member]
Loss Contingencies [Line Items]
Advisement Period	11 months
Michigan Landowners [Member] | Maximum [Member]
Loss Contingencies [Line Items]
Provision for legal contingencies				25
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]
Estimated Litigation Liability						100
Provision for legal contingencies		339
Oklahoma Royalty Settlement [Member]
Loss Contingencies [Line Items]
Estimated Litigation Liability		$ 114		$ 114		119
Oklahoma Royalty Settlement [Member] | Settled Litigation [Member]
Loss Contingencies [Line Items]
Estimated Litigation Liability						$ 119

Commitments - Undiscounted Gath

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) - Gathering and Processing Equipment [Member] $ in Millions	Jun. 30, 2015USD ($)
Other Commitments [Line Items]
Gathering, Processing and Transportation Commitment, Remainder of Year	$ 914
Gathering, Processing and Transportation Commitment, Due in Second Year	1,936
Gathering, Processing and Transportation Commitment, Due in Third Year	1,941
Gathering, Processing and Transportation Commitment, Due in Fourth Year	1,723
Gathering, Processing and TransportationCommitment, Due in Fifth Year	1,437
Gathering, Processing and Transportation Commitment, Due after Fifth Year	6,227
Gathering, Processing and Transportation Commitment	$ 14,178

Commitments - Narrative (Detail

Commitments - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2015USD ($)Crew	Dec. 31, 2014USD ($)	Jul. 20, 2011USD ($)
Long-term Purchase Commitment [Line Items]
Gathering Fee Escalation Rate	15.00%
Investments	$ 255	$ 265
Sundrop Fuels Inc [Member]
Long-term Purchase Commitment [Line Items]
Investments	155		$ 155
Marketable Securities, Equity Securities	25
Drilling Rig Leases [Member]
Long-term Purchase Commitment [Line Items]
Contractual Obligation	$ 353
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	$ 185
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year One of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	7
Year of Service Agreement	1 year
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Two of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	5
Year of Service Agreement	2 years
Pressure Pumping Leases [Member] | Pressure Pumping Crew Year Three of Agreement [Member] | Seven Seven Energy Inc. [Member]
Long-term Purchase Commitment [Line Items]
Number of Crews | Crew	3
Year of Service Agreement	3 years

Other Liabilities - Current Tab

Other Liabilities - Current Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Other Current Liabilities [Line Items]
Accrued Royalties, Current	$ 757	$ 1,176
Accrued Drilling And Production Costs	327	385
Prepayments Received	202	189
Employee-related Liabilities, Current	237	344
Accrual for Taxes Other than Income Taxes, Current	130	55
Dividends Payable, Current	43	101
Other Accrued Liabilities, Current	400	592
Other current liabilities ($11 and $15 attributable to our VIE)	2,649	3,061
Redemption of 2019 Notes [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	439	100
Oklahoma Royalty Settlement [Member]
Other Current Liabilities [Line Items]
Estimated Litigation Liability	$ 114	$ 119

Other Liabilities - Long-Term T

Other Liabilities - Long-Term Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Other Long-Term Liabilities [Line Items]
Financing obligations	$ 29	$ 30
Unrecognized Tax Benefits	46	45
Other long-term liabilities	141	249
Total other long-term liabilities	549	679
Current liabilities	2,649	3,061
Noncontrolling Interest, Chesapeake Utica L L C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	205	220
Total other long-term liabilities	225	234
Current liabilities	20	14
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]
Other Long-Term Liabilities [Line Items]
Conveyance Obligation Noncurrent	128	135
Total other long-term liabilities	156	158
Current liabilities	$ 28	$ 23

Equity - Common Stock Table (De

Equity - Common Stock Table (Details) - shares	6 Months Ended
	Jun. 30, 2015	Jun. 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)	103,000	(2,019,000)
Stock option exercises	14,000	1,268,000
Common Stock, Shares, Issued End of Period	665,060,856	665,441,000

Equity - Convertible Preferred

Equity - Convertible Preferred Stock Table (Details) - shares	Jun. 30, 2015	Dec. 31, 2014	Jun. 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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 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	$ 3	$ (1)	12	$ 8
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(131)		(131)
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			(1)	3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			13	10
Net Other Comprehensive Income			12	13
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(131)	(154)	(131)	(154)
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			(1)	3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			13	5
Net Other Comprehensive Income			12	8
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (131)	$ (154)	$ (131)	$ (154)

Equity - AOCI Reclassifications

Equity - AOCI Reclassifications Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL Reclassifications from AOCI	$ 728	$ 1,704	$ 1,813	$ 3,471
Net gain (loss) on Sales of Investments Reclassifications from AOCI	0	0	0	67
Total Reclassification from AOCI	(4,090)	230	(7,810)	696
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Total Reclassification from AOCI	3	(1)	13	5
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	$ 3	$ (1)	$ 13	$ 10

Equity - Narrative (Details)

Equity - Narrative (Details)	6 Months Ended
	Jun. 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	Jun. 30, 2015USD ($)wella$ / sharesshares	Jul. 31, 2014USD ($)$ / shares	Mar. 30, 2012USD ($)awell	Oct. 31, 2011aCounty	Dec. 31, 2011USD ($)wellshares	Sep. 30, 2015USD ($)	Jun. 30, 2015USD ($)wella$ / sharesshares	Jun. 30, 2014USD ($)shares	Dec. 31, 2011USD ($)shares	Jun. 30, 2015USD ($)awellQuarter$ / sharesshares	Jun. 30, 2014USD ($)wellshares	Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013shares	Mar. 31, 2012shares	Nov. 30, 2011$ / sharesshares
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments										$ 6	$ 5
Restricted cash	$ 38						$ 38			38		$ 38
Stockholders' Equity Attributable to Noncontrolling Interest	$ 1,285						1,285			1,285		$ 1,302
Net income (loss) attributable to noncontrolling interests							$ 18	$ 39		37	80
Proceeds from divestitures of proved and unproved properties										$ 14	$ 248
Common Stock, Shares, Issued | shares	665,060,856						665,060,856	665,441,000		665,060,856	665,441,000	664,944,232	666,192,000
Common stock, par value (usd per share) | $ / shares	$ 0.01						$ 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%						3.75%			3.75%				3.75%
Preferred Stock, Dividends, Per Share, Cash Paid | $ / shares										$ 1,000
Restricted cash	$ 38						$ 38			$ 38
Stockholders' Equity Attributable to Noncontrolling Interest	1,015						1,015			1,015		$ 1,015
Net income (loss) attributable to noncontrolling interests							$ 19	$ 19		$ 38	$ 38
Proceeds from divestitures of proved and unproved properties	$ 575
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Scenario, Forecast [Member]
Noncontrolling Interest [Line Items]
Payments of Dividends						$ 75
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period Through 2013 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal | well										37.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period in 2014 through 2016 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well										25
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Cumulative Well Total [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well										300
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of April 1, 2014 - June 30,2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal | well										162.5
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Minimum, Six-Month Period of June 30,2014 - December 31, 2014 [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net Decimal | well										175
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Future Wells [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well			1,000							1,000
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Drilled Wells [Member] | ORRI [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well										190
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Wells, Percentage Increase in Future Net Wells [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met										5.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Preferred Stock [Member]
Noncontrolling Interest [Line Items]
Preferred Stock, Dividend Rate, Percentage										6.00%
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Cash Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments			$ 225
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member] | Share Distribution [Member]
Noncontrolling Interest [Line Items]
Payments for (Proceeds from) Investments			$ 1,025
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
Overriding Royalty Interest Percentage	3.00%				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%
Net income (loss) attributable to noncontrolling interests								19			37
Number Of Counties Present In Leasehold Land | County				13
Payments for Repurchase of Preferred Stock and Preference Stock		$ 1,254
Preferred Stock Redemption Premium										$ 447
Spacing for Wells Drilled | a	150						150			150
Preferred Stock, Redemption Price Per Share | $ / shares		$ 1,189
Noncontrolling Interest, Chesapeake Utica L L C [Member] | ORRI [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well										463
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Minimum [Member]
Noncontrolling Interest [Line Items]
Number of Wells, Net | well										1,300
Noncontrolling Interest, Chesapeake Utica L L C [Member] | Wells, Percentage Increase in Future Net Wells [Member]
Noncontrolling Interest [Line Items]
Percentage of increase in leasehold in which commitment to drill is not met										4.00%
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]
Noncontrolling Interest [Line Items]
Number Of Net Acres | a										29,000
Stockholders' Equity Attributable to Noncontrolling Interest	$ 271						$ 271			$ 271		$ 287
Net income (loss) attributable to noncontrolling interests							$ 1	$ 2		$ 1	$ 7
Common stock, par value (usd per share) | $ / shares															$ 19
Common shares, outstanding | shares	46,750,000						46,750,000			46,750,000
Percentage Of Beneficial Interest Owned										51.00%
Number of producing wells | well	69						69			69
Number of development wells drilled | well										104	93
Number Of Gross Acres | a										45,400
Maximum amount recoverable by trust under lien									$ 263	$ 32	$ 55
Quarters of Paid Distributions | Quarter										12
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 shares, outstanding | shares	12,062,500						12,062,500			12,062,500
Noncontrolling Interest, Chesapeake Granite Wash Trust [Member] | Subordinated Units [Member]
Noncontrolling Interest [Line Items]
Common shares, outstanding | shares	11,687,500						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
	Feb. 28, 2015	Nov. 30, 2014	Feb. 28, 2014	Nov. 30, 2013
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Distribution Date	Jun. 1, 2015	Mar. 2, 2015	May 30, 2014	Mar. 3, 2014
Common Unit [Member]
Noncontrolling Interest [Line Items]
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	$ 0.3899	$ 0.4496	$ 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

Share-Based Compensation - Rest

Share-Based Compensation - Restricted Stock Table (Details) - 6 months ended Jun. 30, 2015 - Restricted Stock [Member] - $ / shares shares in Thousands	Total
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	6,918
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	(2,651)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(374)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	13,984
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	$ 21.20
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	14.03
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	16.79
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	15.28
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$ 18.65

Share-Based Compensation - Equi

Share-Based Compensation - Equity-Classified Valuation Table (Details) - 6 months ended Jun. 30, 2015 - Employee Stock Option [Member]	Total
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	Jun. 30, 2015	Jun. 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)	(1,268)
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	5,580	4,599	5,580
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	2,169		2,169
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	$ 19.33	$ 19.55	19.33
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	$ 19.44		$ 19.44
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	6 years 4 months 22 days	7 years 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	5 years 7 months 4 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	$ 0	$ 5	0
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	$ 0		$ 0

Share-Based Compensation - Eq70

Share-Based Compensation - Equity-Classified Compensation Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 28	$ 29	$ 52	$ 56
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	12	11	24	24
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	8	9	15	16
Operating Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	6	5	10	8
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	2	1	3	3
Other Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 0	$ 3	$ 0	$ 5

Share-Based Compensation - Liab

Share-Based Compensation - Liability Classified Valuation Table (Details) - Performance Shares [Member]	6 Months Ended
	Jun. 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	40.12%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.95%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.91%

Share-Based Compensation - Perf

Share-Based Compensation - Performance Share Unit Breakout (Details) - Performance Shares [Member] - USD ($) $ in Millions	Jun. 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	$ 13			$ 35
Deferred Compensation Share-based Arrangements, Liability, Current and Noncurrent	$ 12
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	$ 5	$ 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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	$ 28	$ 29	$ 52	$ 56
General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	12	11	24	24
Cost of Sales [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	2	1	3	3
Oil and Gas Properties [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	8	9	15	16
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(9)	29	(31)	20
Performance Shares [Member] | General and Administrative Expense [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(4)	11	(14)	10
Performance Shares [Member] | Restructuring Charges [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Allocated Share-based Compensation Expense	(5)	15	(15)	6
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)	1
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	$ 2	$ (1)	$ 3

Share-Based Compensation - Narr

Share-Based Compensation - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 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	$ 45		$ 45
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	180		$ 180
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition			2 years 2 months 17 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			2 years 7 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	13		$ 13
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, Expiration Period			10 years
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage			33.00%
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]
Increase in tax benefit from stock-based compensation			$ (6)	$ 3
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	0		6
Increase in tax benefit from stock-based compensation		$ 0		3
Paid-In Capital [Member] | Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Increase in tax benefit from stock-based compensation	$ 0	$ 0	$ 0	$ 0

Derivative and Hedging Activi75

Derivative and Hedging Activities - Derivative Instruments Table (Details) MMBbls in Millions, $ in Millions, MMBTU in Trillions	Jun. 30, 2015USD ($)MMBTUMMBbls	Dec. 31, 2014USD ($)MMBTUMMBbls
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 391	$ 652
Crude Oil [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	42	52.7
Derivative Assets (Liabilities), at Fair Value, Net	$ 195	$ 422
Crude Oil [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	7.4	12.5
Derivative Assets (Liabilities), at Fair Value, Net	$ 196	$ 471
Crude Oil [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	2.2	4.4
Derivative Assets (Liabilities), at Fair Value, Net	$ 21	$ 40
Crude Oil [Member] | Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	27.9	35.8
Derivative Assets (Liabilities), at Fair Value, Net	$ (26)	$ (89)
Crude Oil [Member] | Basis Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | MMBbls	4.5	0
Derivative Assets (Liabilities), at Fair Value, Net	$ 4	$ 0
Natural Gas [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 63	$ 299
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	604	735
Natural Gas [Member] | Swap [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 135	$ 281
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	260	275
Natural Gas [Member] | Three Way Collar [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 51	$ 165
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	71	207
Natural Gas [Member] | Call Option [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (128)	$ (170)
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	$ 5	$ 23
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU	80	60
Commodity Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 258	$ 721

Derivative and Hedging Activi76

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 391	$ 652
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	391	652
Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative, Fair Value, Net	258	721
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	258	722
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	258	722
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	0	(17)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	0	(17)
Not Designated as Hedging Instrument [Member] | Other Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	221
Derivative Liability, Fair Value, Gross Asset	0
Derivative, Fair Value, Net	221
Not Designated as Hedging Instrument [Member] | Other Current Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	426	974
Derivative Asset, Fair Value, Gross Liability	(74)	(95)
Derivative, Fair Value, Net	352	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	35
Derivative Asset, Fair Value, Gross Liability	0
Derivative, Fair Value, Net	35
Not Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		16
Derivative Asset, Fair Value, Gross Liability		(10)
Derivative, Fair Value, Net		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	186
Derivative, Fair Value, Net	186
Not Designated as Hedging Instrument [Member] | Other Current Liabilities [Member] | Commodity Contract [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(101)	(105)
Derivative Liability, Fair Value, Gross Asset	74	95
Derivative, Fair Value, Net	(27)	(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	0	(5)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	0	(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	(67)	(163)
Derivative Liability, Fair Value, Gross Asset	0	10
Derivative, Fair Value, Net	(67)	(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	(88)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	(88)	(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	(88)	(53)
Derivative Liability, Fair Value, Gross Asset	0	0
Derivative, Fair Value, Net	$ (88)	$ (53)

Derivative and Hedging Activi77

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gains (losses) on undesignated oil and natural gas derivatives	$ 0	$ 33	$ 10	$ 51
Total oil, natural gas and NGL sales	728	1,704	1,813	3,471
Oil And Gas Exploration And Production [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Oil, natural gas and NGL sales	776	1,917	1,700	4,065
Gains (losses) on undesignated oil and natural gas derivatives	(43)	(210)	135	(574)
Losses on terminated cash flow hedges	$ (5)	$ (3)	$ (22)	$ (20)

Derivative and Hedging Activi78

Derivative and Hedging Activities Derivative and Hedging Activities, Marketing, Gathering and Compression Sales (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Marketing, Gathering and Compression Revenue	$ 2,305	$ 3,167	$ 3,980	$ 6,182
Marketing, Gathering And Compression [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Refining and Marketing Revenue	2,085	3,167	3,760	6,182
Other Contract [Member] | Marketing, Gathering And Compression [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements	27		27
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, Settlements			0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		$ 0	220	$ 0
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member] | Marketing, Gathering And Compression [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	$ 220		$ 220

Derivative and Hedging Activi79

Derivative and Hedging Activities - Components of Interest Income and Interest Expense Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Interest expense on senior notes	$ 171	$ 184	$ 342	$ 364
Interest expense on term loan	0	7	0	36
Amortization of loan discount, issuance costs and other	12	16	23	35
Interest expense on credit facilities	3	9	6	17
Gains on terminated fair value hedges	(1)	(1)	(2)	(2)
Gains on undesignated interest rate derivatives	0	(33)	(10)	(51)
Capitalized interest	(114)	(155)	(237)	(333)
Total interest expense	$ 71	$ 27	$ 122	$ 66

Derivative and Hedging Activi80

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 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 $0 , $1, ($1) and $3	$ 0	$ 0	(1)	$ 3
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $4, $9 and $10	3	(1)	13	10
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	(131)		(131)
Cash Flow Hedging [Member]
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(216)	(247)	(231)	(269)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	(134)	(153)	(143)	(167)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, before Tax	0	1	(2)	6
Unrealized gains (losses) on derivative instruments, net of income tax expense (benefit) of $0 , $1, ($1) and $3			(1)	3
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	5	3	22	20
Reclassification of (gains) losses on settled derivative instruments, net of income tax expense (benefit) of $2, $4, $9 and $10	3	(1)	13	10
Accumulated Other Comprehensive Income (Loss), Before Tax, Period End	(211)	(243)	(211)	(243)
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$ (131)	$ (154)	$ (131)	$ (154)

Derivative and Hedging Activi81

Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 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	$ 391	$ 652
Commodity Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	426	989
Derivative Liability	(168)	(268)
Derivative Assets (Liabilities), at Fair Value, Net	258	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	(88)	(53)
Other Contract [Member]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset	221	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	252	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	353	784
Derivative Liability	(13)	(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	(88)	(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	139	(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	73	205
Derivative Liability	(155)	(259)
Derivative Assets (Liabilities), at Fair Value, Net	(82)	(54)	$ (550)	$ (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	221	1
Derivative Assets (Liabilities), at Fair Value, Net	$ 221	$ 1	$ 0	$ 0

Derivative and Hedging Activi82

Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2015	Jun. 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		391
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		258
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		139
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		80	(173)
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements		(108)	105
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	$ (550)	(82)	(550)
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)		69	(133)
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	0	220	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements		0	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	$ 0	221	0
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)		$ 220	$ 0

Derivative and Hedging Activi83

Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) - Jun. 30, 2015 - USD ($) $ in Millions	Total
Energy Related Derivative, Oil Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	26.97%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (5)
Energy Related Derivative, Oil Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	19.51%
Energy Related Derivative, Oil Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	32.31%
Other Contract [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	20.05%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$ 221
Other Contract [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	16.55%
Other Contract [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	33.27%
Energy Related Derivative, Natural Gas Trades [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	32.19%
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	$ (77)
Energy Related Derivative, Natural Gas Trades [Member] | Minimum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	20.47%
Energy Related Derivative, Natural Gas Trades [Member] | Maximum [Member]
Fair Value Inputs, Assets, Quantitative Information [Line Items]
Weighted Average Of Price Volatility Curve Percentage	56.46%

Derivative and Hedging Activi84

Derivative and Hedging Activities - Narrative (Details) € in Millions, MMBoe in Millions, MMBTU in Millions, $ in Millions	1 Months Ended	3 Months Ended		6 Months Ended
	Dec. 31, 2006USD ($)$ / €	Jun. 30, 2015USD ($)MMBoeMMBTUcounterpartyDerivatives$ / €	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)MMBoecounterpartyDerivatives$ / €	Jun. 30, 2014USD ($)	Jun. 30, 2015EUR (€)MMBoecounterpartyDerivatives$ / €	Apr. 30, 2015USD ($)	Mar. 31, 2015USD ($)	Dec. 31, 2014USD ($)$ / €	Mar. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Dec. 31, 2006EUR (€)$ / €
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		$ 391		$ 391					$ 652
Accumulated other comprehensive loss		131		131					143
Expected amount to be transferred of during the next 12 months		20		20
Derivative Asset, Fair Value, Gross Asset		391		391					652
Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, Amount of Hedged Item		400		$ 400					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
Other Contract [Member]
Derivative [Line Items]
Derivative, Number of Instruments Held | Derivatives		2		2		2
Derivative Asset		$ 221		$ 221					1
Derivative, Nonmonetary Notional Amount, Energy Measure | MMBTU		90,000
Embedded Derivative Financial Instruments [Member]
Derivative [Line Items]
Derivative, Number of Instruments Held | Derivatives		1		1		1
Credit Risk [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty		17		17		17
Multi-Counterparty Hedging Facility [Member]
Derivative [Line Items]
Number of counterparties in hedge facility | counterparty		11		11		11
Borrowing capacity		$ 7,400		$ 7,400
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
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
Multi-Counterparty Hedging Facility [Member] | Energy Related Derivative [Member]
Derivative [Line Items]
Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe) | MMBoe		465		465		465
Multi-Counterparty Hedging Facility [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		40.5		40.5		40.5
Multi-Counterparty Hedging Facility [Member] | Basis Derivative [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		2.3		2.3		2.3
Bilateral Hedging Agreement [Member]
Derivative [Line Items]
Borrowing capacity							$ 16,500
Line of Credit Facility, Current Borrowing Capacity		$ 7,400		$ 7,400
Bilateral Hedging Agreement [Member] | Price Risk Derivative [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		84.2		84.2		84.2
Bilateral Hedging Agreement [Member] | Basis Derivative [Member]
Derivative [Line Items]
Multi-counterparty hedge facility, hedged total (in tcfe) | MMBoe		15.6		15.6		15.6
Marketing, Gathering And Compression [Member] | Other Contract [Member]
Derivative [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements		$ 27		$ 27
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
6.25% Euro-Denominated Senior Notes Due 2017 [ Member] | Senior Notes [Member] | Cross Currency Interest Rate Contract [Member]
Derivative [Line Items]
Euro-denominated debt in notes payable, adjusted value		$ 384		$ 384
Derivative, Forward Exchange Rate | $ / €	1.3325	1.1147		1.1147		1.1147			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
Cash Flow Hedging [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		131	$ 154	131	$ 154			$ 134	$ 143	$ 153	$ 167
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		0		0					(17)
Derivative Liability, Fair Value, Gross Liability		0		0					(17)
Not Designated as Hedging Instrument [Member] | Other Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		221		221
Derivative Asset, Fair Value, Gross Asset		221		221
Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		(88)		(88)					(53)
Derivative Liability, Fair Value, Gross Liability		(88)		(88)					(53)
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Accumulated other comprehensive loss		(123)		(123)
Fair Value, Inputs, Level 3 [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		139		139					(53)
Fair Value, Inputs, Level 3 [Member] | Other Contract [Member]
Derivative [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net		221	0	221	0				1		$ 0
Derivative Asset		221		221					$ 1
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings			$ 0	220	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Settlements				0	$ 0
Fair Value, Inputs, Level 3 [Member] | Marketing, Gathering And Compression [Member] | Other Contract [Member]
Derivative [Line Items]
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings		$ 220		$ 220

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							6 Months Ended
	Mar. 31, 2012USD ($)McfeMBblsMcf	Jun. 30, 2011USD ($)	Sep. 30, 2010USD ($)McfeMBblsMcf	Dec. 31, 2008USD ($)McfeMBblsMcf	Sep. 30, 2008USD ($)	Jun. 30, 2008USD ($)	Dec. 31, 2007USD ($)McfeMBblsMcf	Jun. 30, 2015USD ($)McfeMBblsMcf	May. 31, 2011McfeMBblsMcf	Aug. 31, 2008McfeMBblsMcf	May. 31, 2008McfeMBblsMcf
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $								$ 5,481
Proved Developed Reserves (Energy) | Mcfe								1,220
Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)								5.2
Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf								1,105
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 8 Barnett Shale [Member]
VPP Transactions [Line Items]
Cash Proceeds from Volumetric Production Payment (VPP) | $			$ 1,150
Proved Developed Reserves (Energy) | Mcfe			390
VPP 8 Barnett Shale [Member] | Oil [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)			0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume) | Mcf			390
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [Member]
VPP Transactions [Line Items]
Proved Developed Reserves (Volume)			0
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		6 Months Ended
	Jun. 30, 2015McfeMBblsMcf	Jun. 30, 2014McfeMBblsMcf	Jun. 30, 2015McfeMBblsMcf	Jun. 30, 2014McfeMBblsMcf
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	30.3	37.2	61.6	76.6
Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	131,200	174,700	268,800	357,400
Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	27.2	33.7	55.5	69.2
Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	363,600	433,800	736,900	885,500
VPP 10 Anadarko Basin Granite Wash [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4.3	5.3	8.7	10.8
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	78,000	103,000	161,000	212,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	2.2	2.7	4.4	5.5
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	268,700	329,900	545,000	675,100
VPP 9 Mid-Continent [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	4.4	4.8	8.9	9.7
VPP 9 Mid-Continent [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	42,500	47,500	86,100	96,500
VPP 9 Mid-Continent [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	3.5	3.9	7.2	7.9
VPP 9 Mid-Continent [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	94,900	103,900	191,900	210,400
VPP 8 Barnett Shale [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserve, Production (Energy) | Mcfe	13.6	15.2	27.6	30.9
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	13.6	15.2	27.6	30.9
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	2.3
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	12,000
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	2.2
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	1.7	0	3.5
VPP 5 South Texas [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	6,000	0	12,300
VPP 5 South Texas [Member] | Natural Gas [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production | Mcf	0	1.7	0	3.4
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	2.1	2.3	4.2	4.7
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	10,700	12,200	21,700	24,600
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	2.3	4.1	4.6
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	3.3	3.7
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	3.3	3.7
VPP 3 Anadarko Basin [Member] | Natural Gas Liquids [Member]
VPP Volumes Produced During Period [Line Items]
Proved Developed and Undeveloped Reserves, Production	0	0	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	1.6	2.1	4
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	1.6	2.1	4
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	3.3	3.4	6.8	7
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	3.3	3.4	6.8	7
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	6 Months Ended
	Jun. 30, 2015McfeMBblsMcfMMBbls	May. 31, 2011McfeMBblsMcf	Sep. 30, 2010McfeMBblsMcf	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	1,220
Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe	284
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)	2
Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	1,105
Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	236.8
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)	5.8
VPP 10 Anadarko Basin Granite Wash [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	80 months
Proved Developed Reserves (Energy) | Mcfe	65.4
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	1.2
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	33.6
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas Liquids [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	4.1
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)	68 months
Proved Developed Reserves (Energy) | Mcfe	81
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	66
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 8 Barnett Shale [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Energy) | Mcfe			390
VPP 8 Barnett Shale [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Term remaining (in months)	2 months
Proved Developed Reserves (Energy) | Mcfe	8.9
VPP 8 Barnett Shale [Member] | Oil [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls			0
VPP 8 Barnett Shale [Member] | Oil [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume)	0
VPP 8 Barnett Shale [Member] | Natural Gas [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf			390
VPP 8 Barnett Shale [Member] | Natural Gas [Member] | Reserve Volume Remaining [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | Mcf	8.9
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [Member]
VPP Volumes Remaining to be Delivered [Line Items]
Proved Developed Reserves (Volume) | MBbls			0
VPP 8 Barnett Shale [Member] | Natural Gas Liquids [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]
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)	18 months
Proved Developed Reserves (Energy) | Mcfe	11.6
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)	0.1
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	11.2
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)	49 months
Proved Developed Reserves (Energy) | Mcfe	20.6
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	20.6
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)	46 months
Proved Developed Reserves (Energy) | Mcfe	11.7
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	11.7
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)	90 months
Proved Developed Reserves (Energy) | Mcfe	84.8
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	84.8
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)	6 Months Ended		60 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2013Resource_PlaysJoint_Venture
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties	$ 14,000,000	$ 248,000,000
Corporate Joint Venture [Member]
Business Acquisition [Line Items]
Proceeds from divestitures of proved and unproved properties		240,000,000
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	357,000,000
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	19,000,000	$ 8,000,000
Corporate VPP [Member]
Business Acquisition [Line Items]
Gain (Loss) on Disposition of Other Assets	$ 0

Investments - Schedule of Inves

Investments - Schedule of Investments Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Schedule of Equity Method Investments [Line Items]
Carrying Value of Investments	$ 255	$ 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	$ 106	$ 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	$ 131	$ 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	6 Months Ended
	Jun. 30, 2015	Jun. 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 method accretion adjustments	21
Equity Investment Adjustments	31
Excess carrying value of investment over underlying equity in net assets	23
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity Attributable to Goodwill	14
Sundrop Fuels Inc [Member]
Schedule of Equity Method Investments [Line Items]
Equity Investment Adjustments	4
Excess carrying value of investment over underlying equity in net assets	83
Interest Costs Capitalized	$ 5
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	6 Months Ended
	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 2,051	$ 4,108	$ 1,462	$ 837
Short-term derivative assets	387	879
Proved natural gas and oil properties	62,161	58,594
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	50,302	39,043
Current liabilities	2,649	3,061
Non-Guarantor Subsidiaries [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	30	84	$ 91	$ 38
Current liabilities	56	68
Variable Interest Entities, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	1	1
Short-term derivative assets	5	16
Proved natural gas and oil properties	488	488
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	361	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		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 1	$ (93)	$ 4	$ (115)
Natural Gas Compressors [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	(94)	0	(120)
Gathering and Processing Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	10	0	13
Exploration and Production Equipment [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	(9)	0	(7)
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	0	1	1	1
Other Assets [Member]
Property, Plant and Equipment [Line Items]
Net (gains) losses on sales of fixed assets	$ 1	$ (1)	$ 3	$ (2)

Other Property and Equipment -

Other Property and Equipment - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)Compressor	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)Compressor	Dec. 31, 2014USD ($)
Property, Plant and Equipment [Line Items]
Property and equipment held for sale, net	$ 93		$ 93		$ 93
Gain (Loss) on Disposition of Property Plant Equipment	(1)	$ 93	(4)	$ 115
Compressor [Member]
Property, Plant and Equipment [Line Items]
Equipment, Number of Units | Compressor		337		102
Proceeds from Sale of Property, Plant, and Equipment		$ 362		$ 159
Gain (Loss) on Disposition of Property Plant Equipment		93		24
Land and Building [Member]
Property, Plant and Equipment [Line Items]
Gain (Loss) on Disposition of Property Plant Equipment	0	$ (1)	(1)	$ (1)
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	$ 93		$ 93		$ 93

Impairments - Narrative (Detail

Impairments - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)Compressor	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)Rigs
Impaired Long-Lived Assets Held and Used [Line Items]
Impairment of oil and natural gas properties	$ 5,015	$ 0	$ 9,991	$ 0
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	190		190
Impairments of fixed assets and other	84	40	88	60
Gain (Loss) on Contract Termination	(3)		$ (7)
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	13
Net Acreage Shortfall [Member]
Impaired Long-Lived Assets Held and Used [Line Items]
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
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

Spin-Off of Oilfield Services95

Spin-Off of Oilfield Services Business - Narrative (Details) - USD ($) $ in Millions	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Stockholders' equity decreased amount					$ (268)
Restructuring and other termination costs		$ (4)	$ 33	$ (14)	26
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		152
Restructuring and other termination costs					12
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		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		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		$ 500
Debt Instrument, Interest Rate, Stated Percentage	6.50%		6.50%		6.50%
General Partner Distributions	$ 391

Fair Value Measurements - Asset

Fair Value Measurements - Assets and Liabilities Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	$ (1)	$ (1)
Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	62	57
Other Current Liabilities [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Liabilities, Fair Value Disclosure	(63)	(58)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Fair Value, Net Asset (Liability)	(1)	(1)
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other Assets, Fair Value Disclosure	62	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	(63)	(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 ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Total Revenues	$ 3,033	$ 5,152	$ 5,793	$ 10,198
Income (Loss) Before Income Taxes	(5,596)	371	(10,688)	1,117
TOTAL ASSETS	28,598		28,598		$ 40,751
Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	728	1,704	1,813	3,471
Income (Loss) Before Income Taxes	(5,785)	410
Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	2,305	3,167	3,980	6,181
Income (Loss) Before Income Taxes	134	109
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	278	0	516
Income (Loss) Before Income Taxes	0	19
Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	3	0	30
Income (Loss) Before Income Taxes	(31)	(20)
Reportable Subsegments [Member]
Segment Reporting Information [Line Items]
Total Revenues	3,033	5,152	5,793	10,198
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	699	1,704	1,761	3,471
Income (Loss) Before Income Taxes			(11,134)	1,098
TOTAL ASSETS	22,815		22,815		35,381
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	3,509	5,355	6,417	10,777
Income (Loss) Before Income Taxes			138	213
TOTAL ASSETS	1,946		1,946		1,978
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	552	0	1,060
Income (Loss) Before Income Taxes			0	(16)
TOTAL ASSETS	0		0		0
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	3	0	30
Income (Loss) Before Income Taxes			(45)	39
TOTAL ASSETS	4,364		4,364		4,283
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	0	0	0
Income (Loss) Before Income Taxes	86	(147)	353	(217)
Intersegment Eliminations [Member] | Oil And Gas Exploration And Production [Member]
Segment Reporting Information [Line Items]
Total Revenues	29	0	52	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,204)	(2,188)	(2,437)	(4,596)
Intersegment Eliminations [Member] | Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	(274)	0	(544)
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	(1,175)	(2,462)	(2,385)	(5,140)
TOTAL ASSETS	(527)		(527)		$ (891)
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 1,175	$ 2,462	$ 2,385	$ 5,140

Segment Information - Narrative

Segment Information - Narrative (Details) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015USD ($)	Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)Segment	Jun. 30, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			2
Total Revenues	$ 3,033	$ 5,152	$ 5,793	$ 10,198
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	2,305	3,167	3,980	6,181
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	(1,204)	(2,188)	(2,437)	(4,596)
Oilfield Services [Member]
Segment Reporting Information [Line Items]
Total Revenues	0	278	0	516
Oilfield Services [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Total Revenues	$ 0	$ (274)	$ 0	$ (544)

Condensed Consolidating Finan99

Condensed Consolidating Financial Information - Balance Sheet Table (Details) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 2,051	$ 4,108	$ 1,462	$ 837
Restricted cash	38	38
Other current assets	254	207
Intercompany receivable, net	0	0
Total Current Assets	4,231	7,468
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	21,284	30,143
Other property and equipment, net	2,238	2,279
Property and equipment held for sale, net	93	93
Total Property and Equipment, Net	23,615	32,515
LONG-TERM ASSETS:
Other long-term assets	311	497
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	28,598	40,751
CURRENT LIABILITIES:
Current liabilities	2,649	3,061
Intercompany payable, net	0	0
Total Current Liabilities	5,128	5,863
LONG-TERM LIABILITIES:
Long-term debt, net	10,655	11,154
Deferred income tax liabilities	1,408	4,185
Other long-term liabilities	549	679
Total Long-Term Liabilities	13,227	16,683
EQUITY:
Chesapeake stockholders’ equity	8,958	16,903
Noncontrolling interests	1,285	1,302
Total Equity	10,243	18,205	18,325
TOTAL LIABILITIES AND EQUITY	28,598	40,751
Parent Company Member]
CURRENT ASSETS:
Cash and cash equivalents	2,148	4,100	1,396	799
Restricted cash	0	0
Other current assets	78	55
Intercompany receivable, net	24,917	24,527
Total Current Assets	27,143	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	121	153
Investments in subsidiaries and intercompany advances	(5,967)	126
TOTAL ASSETS	21,297	28,961
CURRENT LIABILITIES:
Current liabilities	1,547	792
Intercompany payable, net	0	0
Total Current Liabilities	1,547	792
LONG-TERM LIABILITIES:
Long-term debt, net	10,655	11,154
Deferred income tax liabilities	0	0
Other long-term liabilities	137	112
Total Long-Term Liabilities	10,792	11,266
EQUITY:
Chesapeake stockholders’ equity	8,958	16,903
Noncontrolling interests	0	0
Total Equity	8,958	16,903
TOTAL LIABILITIES AND EQUITY	21,297	28,961
Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	1	2	0	0
Restricted cash	0	0
Other current assets	2,013	3,174
Intercompany receivable, net	0	0
Total Current Assets	2,014	3,176
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	19,478	28,358
Other property and equipment, net	2,237	2,276
Property and equipment held for sale, net	93	93
Total Property and Equipment, Net	21,808	30,727
LONG-TERM ASSETS:
Other long-term assets	614	618
Investments in subsidiaries and intercompany advances	188	467
TOTAL ASSETS	24,624	34,988
CURRENT LIABILITIES:
Current liabilities	3,653	5,081
Intercompany payable, net	24,785	24,940
Total Current Liabilities	28,438	30,021
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	1,263	3,751
Other long-term liabilities	890	1,090
Total Long-Term Liabilities	2,153	4,841
EQUITY:
Chesapeake stockholders’ equity	(5,967)	126
Noncontrolling interests	0	0
Total Equity	(5,967)	126
TOTAL LIABILITIES AND EQUITY	24,624	34,988
Non-Guarantor Subsidiaries [Member]
CURRENT ASSETS:
Cash and cash equivalents	30	84	91	38
Restricted cash	38	38
Other current assets	51	93
Intercompany receivable, net	365	341
Total Current Assets	484	556
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	716	1,112
Other property and equipment, net	1	3
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	717	1,115
LONG-TERM ASSETS:
Other long-term assets	27	26
Investments in subsidiaries and intercompany advances	0	0
TOTAL ASSETS	1,228	1,697
CURRENT LIABILITIES:
Current liabilities	56	68
Intercompany payable, net	0	0
Total Current Liabilities	56	68
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	78	234
Other long-term liabilities	137	142
Total Long-Term Liabilities	215	376
EQUITY:
Chesapeake stockholders’ equity	957	1,253
Noncontrolling interests	0	0
Total Equity	957	1,253
TOTAL LIABILITIES AND EQUITY	1,228	1,697
Eliminations [Member]
CURRENT ASSETS:
Cash and cash equivalents	(128)	(78)	$ (25)	$ 0
Restricted cash	0	0
Other current assets	0	0
Intercompany receivable, net	(25,282)	(24,868)
Total Current Assets	(25,410)	(24,946)
PROPERTY AND EQUIPMENT:
Oil and natural gas properties, at cost based on full cost accounting, net	1,090	673
Other property and equipment, net	0	0
Property and equipment held for sale, net	0	0
Total Property and Equipment, Net	1,090	673
LONG-TERM ASSETS:
Other long-term assets	(10)	(29)
Investments in subsidiaries and intercompany advances	5,779	(593)
TOTAL ASSETS	(18,551)	(24,895)
CURRENT LIABILITIES:
Current liabilities	(128)	(78)
Intercompany payable, net	(24,785)	(24,940)
Total Current Liabilities	(24,913)	(25,018)
LONG-TERM LIABILITIES:
Long-term debt, net	0	0
Deferred income tax liabilities	67	200
Other long-term liabilities	0	0
Total Long-Term Liabilities	67	200
EQUITY:
Chesapeake stockholders’ equity	5,010	(1,379)
Noncontrolling interests	1,285	1,302
Total Equity	6,295	(77)
TOTAL LIABILITIES AND EQUITY	(18,551)	(24,895)
Consolidated Entities [Member]
CURRENT ASSETS:
Other current assets	2,142	3,322
LONG-TERM ASSETS:
Other long-term assets	752	768
CURRENT LIABILITIES:
Current liabilities	5,128	5,863
LONG-TERM LIABILITIES:
Other long-term liabilities	$ 1,164	$ 1,344

Condensed Consolidating Fina100

Condensed Consolidating Financial Information -Statement Of Operations Table (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
REVENUES:
Oil, natural gas and NGL	$ 728	$ 1,704	$ 1,813	$ 3,471
Marketing, gathering and compression	2,305	3,167	3,980	6,182
Oilfield services	0	281	0	545
Total Revenues	3,033	5,152	5,793	10,198
OPERATING EXPENSES:
Oil, natural gas and NGL production	276	282	575	570
Production taxes	34	72	62	122
Marketing, gathering and compression	2,096	3,166	3,796	6,147
Oilfield services	0	212	0	431
General and administrative	69	90	125	169
Restructuring and other termination costs	(4)	33	(14)	26
Provision for legal contingencies	334	0	359	0
Oil, natural gas and NGL depreciation, depletion and amortization	601	661	1,285	1,288
Depreciation and amortization of other assets	34	79	69	157
Impairment of oil and natural gas properties	5,015	0	9,991	0
Impairments of fixed assets and other	84	40	88	60
Net gains (losses) on sales of fixed assets	1	(93)	4	(115)
Total Operating Expenses	8,540	4,542	16,340	8,855
INCOME FROM OPERATIONS	(5,507)	610	(10,547)	1,343
OTHER INCOME (EXPENSE):
Interest expense	(71)	(27)	(122)	(66)
Gains (losses) on investments	(17)	(24)	(24)	(45)
Net gain (loss) on sales of investments	0	0	0	67
Gains (losses) on purchases of debt	0	(195)	0	(195)
Other income (expense)	(1)	7	5	13
Equity in net earnings (losses) of subsidiary	0	0	0	0
Total Other Income (Expense)	(89)	(239)	(141)	(226)
Income (Loss) Before Income Taxes	(5,596)	371	(10,688)	1,117
INCOME TAX EXPENSE (BENEFIT)	(1,506)	141	(2,878)	421
NET INCOME (LOSS)	(4,090)	230	(7,810)	696
Net income attributable to noncontrolling interests	(18)	(39)	(37)	(80)
Net income (loss) attributable to Chesapeake	(4,108)	191	(7,847)	616
Other Comprehensive Income (Loss), Net of Tax	3	(1)	12	8
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4,105)	190	(7,835)	624
Parent Company Member]
REVENUES:
Oil, natural gas and NGL	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services		0		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		0
General and administrative	0	0	1	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies	339		339
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	339	0	340	0
INCOME FROM OPERATIONS	(339)	0	(340)	0
OTHER INCOME (EXPENSE):
Interest expense	(180)	(156)	(351)	(347)
Gains (losses) on investments	0	0	0	0
Net gain (loss) on sales of investments				0
Gains (losses) on purchases of debt		(195)		(195)
Other income (expense)	81	136	(39)	479
Equity in net earnings (losses) of subsidiary	(3,792)	324	(7,314)	655
Total Other Income (Expense)	(3,891)	109	(7,704)	592
Income (Loss) Before Income Taxes	(4,230)	109	(8,044)	592
INCOME TAX EXPENSE (BENEFIT)	(122)	(82)	(197)	(24)
NET INCOME (LOSS)	(4,108)	191	(7,847)	616
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(4,108)	191	(7,847)	616
Other Comprehensive Income (Loss), Net of Tax	0	1	(2)	3
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(4,108)	192	(7,849)	619
Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	693	1,618	1,729	3,282
Marketing, gathering and compression	2,305	3,166	3,980	6,180
Oilfield services		23		40
Total Revenues	2,998	4,807	5,709	9,502
OPERATING EXPENSES:
Oil, natural gas and NGL production	267	272	554	549
Production taxes	33	70	60	119
Marketing, gathering and compression	2,096	3,166	3,796	6,145
Oilfield services		22		54
General and administrative	67	68	121	124
Restructuring and other termination costs	(4)	30	(14)	23
Provision for legal contingencies	(5)		20
Oil, natural gas and NGL depreciation, depletion and amortization	586	615	1,249	1,201
Depreciation and amortization of other assets	34	38	69	78
Impairment of oil and natural gas properties	5,012	0	9,983	0
Impairments of fixed assets and other	84	37	88	37
Net gains (losses) on sales of fixed assets	1	(85)	4	(109)
Total Operating Expenses	8,171	4,233	15,930	8,221
INCOME FROM OPERATIONS	(5,173)	574	(10,221)	1,281
OTHER INCOME (EXPENSE):
Interest expense	(37)	(3)	(74)	(3)
Gains (losses) on investments	(17)	(19)	(24)	(42)
Net gain (loss) on sales of investments				67
Gains (losses) on purchases of debt	0			0
Other income (expense)	(7)	29	7	(114)
Equity in net earnings (losses) of subsidiary	(154)	(32)	(333)	(111)
Total Other Income (Expense)	(215)	(25)	(424)	(203)
Income (Loss) Before Income Taxes	(5,388)	549	(10,645)	1,078
INCOME TAX EXPENSE (BENEFIT)	(1,404)	221	(2,778)	448
NET INCOME (LOSS)	(3,984)	328	(7,867)	630
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(3,984)	328	(7,867)	630
Other Comprehensive Income (Loss), Net of Tax	3	(2)	14	5
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(3,981)	326	(7,853)	635
Non-Guarantor Subsidiaries [Member]
REVENUES:
Oil, natural gas and NGL	35	88	84	192
Marketing, gathering and compression	0	1	0	2
Oilfield services		499		983
Total Revenues	35	588	84	1,177
OPERATING EXPENSES:
Oil, natural gas and NGL production	9	10	21	21
Production taxes	1	2	2	3
Marketing, gathering and compression	0	0	0	2
Oilfield services		375		769
General and administrative	2	22	3	45
Restructuring and other termination costs	0	3	0	3
Provision for legal contingencies	0		0
Oil, natural gas and NGL depreciation, depletion and amortization	23	36	55	79
Depreciation and amortization of other assets	0	71	0	143
Impairment of oil and natural gas properties	186	38	406	98
Impairments of fixed assets and other	0	3	0	23
Net gains (losses) on sales of fixed assets	0	(8)	0	(6)
Total Operating Expenses	221	552	487	1,180
INCOME FROM OPERATIONS	(186)	36	(403)	(3)
OTHER INCOME (EXPENSE):
Interest expense	0	(20)	0	(42)
Gains (losses) on investments	0	(5)	0	(5)
Net gain (loss) on sales of investments				0
Gains (losses) on purchases of debt	0			0
Other income (expense)	0	0	0	1
Equity in net earnings (losses) of subsidiary	0	0	0	0
Total Other Income (Expense)	0	(25)	0	(46)
Income (Loss) Before Income Taxes	(186)	11	(403)	(49)
INCOME TAX EXPENSE (BENEFIT)	(50)	4	(107)	(18)
NET INCOME (LOSS)	(136)	7	(296)	(31)
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	(136)	7	(296)	(31)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	(136)	7	(296)	(31)
Eliminations [Member]
REVENUES:
Oil, natural gas and NGL	0	(2)	0	(3)
Marketing, gathering and compression	0	0	0	0
Oilfield services		(241)		(478)
Total Revenues	0	(243)	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		(185)		(392)
General and administrative	0	0	0	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies	0		0
Oil, natural gas and NGL depreciation, depletion and amortization	(8)	10	(19)	8
Depreciation and amortization of other assets	0	(30)	0	(64)
Impairment of oil and natural gas properties	(183)	(38)	(398)	(98)
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	(191)	(243)	(417)	(546)
INCOME FROM OPERATIONS	191	0	417	65
OTHER INCOME (EXPENSE):
Interest expense	146	152	303	326
Gains (losses) on investments	0	0	0	2
Net gain (loss) on sales of investments				0
Gains (losses) on purchases of debt	0			0
Other income (expense)	(75)	(158)	37	(353)
Equity in net earnings (losses) of subsidiary	3,946	(292)	7,647	(544)
Total Other Income (Expense)	4,017	(298)	7,987	(569)
Income (Loss) Before Income Taxes	4,208	(298)	8,404	(504)
INCOME TAX EXPENSE (BENEFIT)	70	(2)	204	15
NET INCOME (LOSS)	4,138	(296)	8,200	(519)
Net income attributable to noncontrolling interests	(18)	(39)	(37)	(80)
Net income (loss) attributable to Chesapeake	4,120	(335)	8,163	(599)
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 4,120	$ (335)	$ 8,163	$ (599)

Condensed Consolidating Fina101

Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	$ 737	$ 2,643
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,168)	(1,996)
Acquisitions of proved and unproved properties	(266)	(356)
Proceeds from divestitures of proved and unproved properties	14	248
Additions to other property and equipment	(93)	(620)
Other investing activities	0	(3)
Net Cash Used In Investing Activities	(2,512)	(1,780)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings	0	857
Payments on credit facilities borrowings	0	(1,239)
Proceeds from issuance of senior notes, net of discount and offering costs		3,460
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	0	394
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	(3,362)
Other financing activities	(21)	0
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	(282)	(238)
Net increase (decrease) in cash and cash equivalents	(2,057)	625
Cash and cash equivalents, beginning of period	4,108	837
Cash and cash equivalents, end of period	2,051	1,462
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:
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 senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		(3,362)
Other financing activities	(565)	(193)
Intercompany advances, net	(1,387)	1,186
Net Cash Used In Financing Activities	(1,952)	597
Net increase (decrease) in cash and cash equivalents	(1,952)	597
Cash and cash equivalents, beginning of period	4,100	799
Cash and cash equivalents, end of period	2,148	1,396
Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	638	2,337
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(2,077)	(1,946)
Acquisitions of proved and unproved properties	(266)	(354)
Proceeds from divestitures of proved and unproved properties	14	247
Additions to other property and equipment	(93)	(368)
Other investing activities	(2)	877
Net Cash Used In Investing Activities	(2,424)	(1,544)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		140
Payments on credit facilities borrowings		(140)
Proceeds from issuance of senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	398	(29)
Intercompany advances, net	1,387	(764)
Net Cash Used In Financing Activities	1,785	(793)
Net increase (decrease) in cash and cash equivalents	(1)	0
Cash and cash equivalents, beginning of period	2	0
Cash and cash equivalents, end of period	1	0
Non-Guarantor Subsidiaries [Member]
Condensed Financial Statements, Captions [Line Items]
Net Cash Provided By Operating Activities	99	306
CASH FLOWS FROM INVESTING ACTIVITIES:
Drilling and completion costs	(91)	(50)
Acquisitions of proved and unproved properties	0	(2)
Proceeds from divestitures of proved and unproved properties	0	1
Additions to other property and equipment	0	(252)
Other investing activities	3	60
Net Cash Used In Investing Activities	(88)	(243)
CASH FLOWS FROM FINANCING ACTIVITIES:
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 senior notes, net of discount and offering costs		394
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	(65)	(94)
Intercompany advances, net	0	(422)
Net Cash Used In Financing Activities	(65)	(10)
Net increase (decrease) in cash and cash equivalents	(54)	53
Cash and cash equivalents, beginning of period	84	38
Cash and cash equivalents, end of period	30	91
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	0	7
Net Cash Used In Investing Activities	0	7
CASH FLOWS FROM FINANCING ACTIVITIES:
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 senior notes, net of discount and offering costs		0
Proceeds from issuance of oilfield services term loan, net of issuance costs		0
Other financing activities	(50)	(32)
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	(50)	(32)
Net increase (decrease) in cash and cash equivalents	(50)	(25)
Cash and cash equivalents, beginning of period	(78)	0
Cash and cash equivalents, end of period	(128)	(25)
Consolidated Entities [Member]
CASH FLOWS FROM INVESTING ACTIVITIES:
Other investing activities	1	944
CASH FLOWS FROM FINANCING ACTIVITIES:
Other financing activities	$ (282)	$ (348)

Condensed Consolidating Fina102

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