Chesapeake Energy (CHK) 10-Q 6 Nov 14 2014 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2014	Oct. 31, 2014
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'CHK	'
Entity Registrant Name	'CHESAPEAKE ENERGY CORP	'
Entity Central Index Key	'0000895126	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	665,110,655

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$90	$837
Restricted cash	38	75
Accounts receivable, net	2,447	2,222
Short-term derivative assets	100	0
Deferred income tax asset	129	223
Other current assets	325	299
Total Current Assets	3,129	3,656
Natural gas and oil properties, at cost based on full cost accounting:	'	'
Proved natural gas and oil properties ($488 and $488 attributable to our VIE)	60,260	56,157
Unproved properties	11,513	12,013
Oilfield services equipment	0	2,192
Other property and equipment	3,127	3,203
Total Property and Equipment, at Cost	74,900	73,565
Less: accumulated depreciation, depletion and amortization (($220) and ($168) attributable to our VIE)	-38,349	-37,161
Property and equipment held for sale, net	101	730
Total Property and Equipment, Net	36,652	37,134
LONG-TERM ASSETS:	'	'
Investments	254	477
Long-term derivative assets	14	4
Other long-term assets	469	511
TOTAL ASSETS	40,518	41,782
CURRENT LIABILITIES:	'	'
Accounts payable	2,258	1,596
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	71	208
Accrued interest	138	200
Other current liabilities ($16 and $22 attributable to our VIE)	3,135	3,511
Total Current Liabilities	5,602	5,515
LONG-TERM LIABILITIES:	'	'
Long-term debt, net	11,592	12,886
Deferred income tax liabilities	4,285	3,407
Long-term derivative liabilities	294	445
Asset retirement obligations	427	405
Other long-term liabilities	687	984
Total Long-Term Liabilities	17,285	18,127
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: 665,046,461 and 666,192,371 shares issued	7	7
Paid-in capital	12,495	12,446
Retained earnings	945	688
Accumulated other comprehensive loss	-151	-162
Less: treasury stock, at cost; 1,657,456 and 2,002,029 common shares	-38	-46
Total Chesapeake Stockholders’ Equity	16,320	15,995
Noncontrolling interests	1,311	2,145
Total Equity	17,631	18,140
TOTAL LIABILITIES AND EQUITY	$40,518	$41,782

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, except Share data, unless otherwise specified
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	665,046,461	666,192,371
Treasury stock, shares	1,657,456	2,002,029
Cash and cash equivalents	$90	$837
Proved natural gas and oil properties ($488 and $488 attributable to our VIE)	60,260	56,157
Less: accumulated depreciation, depletion and amortization (($220) and ($168) attributable to our VIE)	-38,349	-37,161
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	71	208
Other current liabilities ($16 and $22 attributable to our VIE)	3,135	3,511
Variable Interest Entities, Primary Beneficiary [Member]	'	'
Cash and cash equivalents	1	1
Proved natural gas and oil properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($220) and ($168) attributable to our VIE)	-220	-168
Short-term derivative liabilities ($0 and $5 attributable to our VIE)	0	5
Other current liabilities ($16 and $22 attributable to our VIE)	$16	$22

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
REVENUES:	'	'	'	'
Natural gas, oil and NGL	$2,341	$1,586	$5,812	$5,444
Marketing, gathering and compression	3,362	3,032	9,543	6,871
Oilfield services	0	249	546	650
Total Revenues	5,703	4,867	15,901	12,965
OPERATING EXPENSES:	'	'	'	'
Natural gas, oil and NGL production	298	282	868	877
Production taxes	62	62	185	173
Marketing, gathering and compression	3,369	3,009	9,515	6,781
Oilfield services	0	211	431	543
General and administrative	60	120	229	336
Restructuring and other termination costs	-14	63	12	203
Provision for legal contingencies	100	0	100	0
Natural gas, oil and NGL depreciation, depletion and amortization	688	652	1,977	1,945
Depreciation and amortization of other assets	37	79	194	234
Impairments of fixed assets and other	15	85	75	343
Net gains on sales of fixed assets	-86	-132	-201	-290
Total Operating Expenses	4,529	4,431	13,385	11,145
INCOME FROM OPERATIONS	1,174	436	2,516	1,820
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-17	-40	-82	-164
Losses on investments	-27	-22	-72	-36
Net gain (loss) on sales of investments	0	3	67	-7
Losses on purchases of debt	0	0	-195	-70
Other income (expense)	-1	10	12	18
Total Other Expense	-45	-49	-270	-259
INCOME BEFORE INCOME TAXES	1,129	387	2,246	1,561
INCOME TAX EXPENSE:	'	'	'	'
Current income taxes	2	7	10	9
Deferred income taxes	435	140	849	585
Total Income Tax Expense	437	147	859	594
NET INCOME	692	240	1,387	967
Net income attributable to noncontrolling interests	-30	-38	-110	-127
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	662	202	1,277	840
Preferred stock dividends	-43	-43	-128	-128
Redemption of preferred shares of a subsidiary	-447	0	-447	-69
Earnings allocated to participating securities	-3	-3	-15	-14
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$169	$156	$687	$629
EARNINGS PER COMMON SHARE:	'	'	'	'
Earnings Per Share, Basic	$0.26	$0.24	$1.04	$0.96
Earnings Per Share, Diluted	$0.26	$0.24	$1.04	$0.96
CASH DIVIDEND DECLARED PER COMMON SHARE	$0.09	$0.09	$0.26	$0.26
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):	'	'	'	'
Weighted Average Number of Shares Outstanding, Basic	660	656	659	654
Weighted Average Number of Shares Outstanding, Diluted	660	656	659	654

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Statement of Comprehensive Income [Abstract]	'	'	'	'
NET INCOME	$692	$240	$1,387	$967
OTHER COMPREHENSIVE INCOME, NET OF INCOME TAX:	'	'	'	'
Unrealized gain on derivative instruments, net of income tax expense of $0, $1, $3 and $1	0	2	3	2
Reclassification of loss on settled derivative instruments, net of income tax expense of $2, $1, $12 and $8	3	2	13	13
Unrealized loss on investments, net of income tax benefit of $0, ($1), $0 and ($4)	0	-1	0	-6
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $0, ($1), ($3) and $3	0	-2	-5	4
Other Comprehensive Income	3	1	11	13
COMPREHENSIVE INCOME	695	241	1,398	980
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	-30	-38	-110	-127
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$665	$203	$1,288	$853

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Unrealized gain on derivative instruments, net of income tax expense of $0, $1, $3 and $1	$0	$1	$3	$1
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	2	1	12	8
Unrealized loss on investments, net of income tax benefit of $0, ($1), $0 and ($4)	0	-1	0	-4
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	$0	($1)	($3)	$3

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME	$1,387	$967
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:	'	'
Depreciation, depletion and amortization	2,171	2,179
Deferred income tax expense	849	585
Derivative gains, net	-20	-90
Cash payments on derivative settlements, net	-341	-66
Stock-based compensation	59	78
Net gains on sales of fixed assets	-201	-290
Impairments of fixed assets and other	44	317
Losses on investments	72	40
Net (gains) losses on sales of investments	-67	7
Restructuring and other termination costs	-18	164
Provision for legal contingencies	100	0
Losses on purchases of debt	61	37
Other	57	30
Changes in assets and liabilities	-348	-372
Net Cash Provided By Operating Activities	3,805	3,586
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-3,185	-4,470
Acquisitions of proved and unproved properties	-1,023	-811
Proceeds from divestitures of proved and unproved properties	723	2,789
Additions to other property and equipment	-675	-639
Proceeds from sales of other property and equipment	964	796
Additions to investments	-14	-8
Proceeds from sales of investments	239	115
Decrease in restricted cash	37	177
Other	-4	4
Net Cash Used In Investing Activities	-2,938	-2,047
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	3,573	7,136
Payments on credit facilities borrowings	-3,896	-7,268
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	3,460	'
Proceeds from issuance of oilfield services term loan, net of issuance costs	394	0
Cash paid to purchase debt	-3,362	-2,141
Cash paid for common stock dividends	-175	-175
Cash paid for preferred stock dividends	-128	-128
Cash paid on financing derivatives	-50	-62
Cash paid for prepayment of mortgage	0	-55
Proceeds from sales of noncontrolling interests	0	5
Proceeds from other financings	0	22
Cash paid to purchase preferred shares of a subsidiary	-1,254	-212
Cash held and retained by SSE at spin-off	-8	0
Distributions to noncontrolling interest owners	-143	-164
Other	-25	-71
Net Cash Used In Financing Activities	-1,614	-839
Net increase (decrease) in cash and cash equivalents	-747	700
Cash and cash equivalents, beginning of period	837	287
Cash and cash equivalents, end of period	90	987
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'
Interest paid, net of capitalized interest	88	62
Income taxes paid, net of refunds received	17	14
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:	'	'
Change in accrued drilling and completion costs	-64	-97
Change in accrued acquisitions of proved and unproved properties	-100	-1
Change in accrued additions to other property and equipment	-11	-80
Chesapeake Energy [Member]	'	'
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	2,966	2,274
Chesapeake Oilfield Operating [Member]	'	'
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of senior notes, net of discount and offering costs	494	0
Proceeds from issuance of oilfield services senior notes, net of discount and offering costs	$494	$0

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited) (USD $)	Total	Preferred Stock [Member]	Common Stock [Member]	Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	Accumulated Net Unrealized Investment Gain (Loss) [Member]	Treasury Stock - Common [Member]	Parent [Member]	Noncontrolling Interest [Member]
In Millions, unless otherwise specified
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2012	'	'	'	'	'	'	'	'	'	'	$2,327
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2012	'	'	'	12,293	437	-182	'	'	-48	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'	'
Stock-based compensation	'	'	'	156	'	'	'	'	'	'	'
Reduction in tax benefit from stock-based compensation	'	'	'	-10	'	'	'	'	'	'	'
Exercise of stock options	'	'	'	4	'	'	'	'	'	'	'
Net income attributable to Chesapeake	840	'	'	'	840	'	'	'	'	'	'
Dividends on common stock	'	'	'	'	-175	'	'	'	'	'	'
Dividends on preferred stock	-128	'	'	'	-128	'	'	'	'	'	'
Spin-off of oilfield services business (Note 2)	'	'	'	'	0	'	'	'	'	'	'
Redemption of preferred shares of a subsidiary	-69	'	'	'	-69	'	'	'	'	'	'
Hedging activity	'	'	'	'	'	'	15	'	'	'	'
Investment activity	'	'	'	'	'	'	'	-2	'	'	'
Purchase of 24,859 and 249,498 shares for company benefit plans	'	'	'	'	'	'	'	'	-6	'	'
Release of 369,432 and 151,153 shares from company benefit plans	'	'	'	'	'	'	'	'	2	'	'
Sales of noncontrolling interests	'	'	'	'	'	'	'	'	'	'	5
Net income attributable to noncontrolling interests	127	'	'	'	'	'	'	'	'	'	127
Distributions to noncontrolling interest owners	'	'	'	'	'	'	'	'	'	'	-164
Redemption of preferred shares of a subsidiary	'	'	'	'	'	'	'	'	'	'	-143
Total Equity	18,348	'	'	'	'	'	'	'	'	'	'
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Sep. 30, 2013	'	'	'	'	'	'	'	'	'	'	2,152
Chesapeake stockholders’ equity, end of period at Sep. 30, 2013	'	3,062	7	12,443	905	-169	'	'	-52	16,196	'
Stockholders' Equity Attributable to Noncontrolling Interest, Period Start at Dec. 31, 2013	2,145	'	'	'	'	'	'	'	'	'	2,145
Chesapeake stockholders’ equity, beginning of period at Dec. 31, 2013	15,995	'	'	12,446	688	-162	'	'	-46	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'	'	'	'
Stock-based compensation	'	'	'	26	'	'	'	'	'	'	'
Reduction in tax benefit from stock-based compensation	'	'	'	-1	'	'	'	'	'	'	'
Exercise of stock options	'	'	'	24	'	'	'	'	'	'	'
Net income attributable to Chesapeake	1,277	'	'	'	1,277	'	'	'	'	'	'
Dividends on common stock	'	'	'	'	-175	'	'	'	'	'	'
Dividends on preferred stock	-128	'	'	'	-128	'	'	'	'	'	'
Spin-off of oilfield services business (Note 2)	'	'	'	'	-270	'	'	'	'	'	'
Redemption of preferred shares of a subsidiary	-447	'	'	'	-447	'	'	'	'	'	'
Hedging activity	'	'	'	'	'	'	16	'	'	'	'
Investment activity	'	'	'	'	'	'	'	-5	'	'	'
Purchase of 24,859 and 249,498 shares for company benefit plans	'	'	'	'	'	'	'	'	-1	'	'
Release of 369,432 and 151,153 shares from company benefit plans	'	'	'	'	'	'	'	'	9	'	'
Sales of noncontrolling interests	'	'	'	'	'	'	'	'	'	'	0
Net income attributable to noncontrolling interests	110	'	'	'	'	'	'	'	'	'	110
Distributions to noncontrolling interest owners	'	'	'	'	'	'	'	'	'	'	-137
Redemption of preferred shares of a subsidiary	'	'	'	'	'	'	'	'	'	'	-807
Total Equity	17,631	'	'	'	'	'	'	'	'	'	'
Stockholders' Equity Attributable to Noncontrolling Interest, Period End at Sep. 30, 2014	1,311	'	'	'	'	'	'	'	'	'	1,311
Chesapeake stockholders’ equity, end of period at Sep. 30, 2014	$16,320	$3,062	$7	$12,495	$945	($151)	'	'	($38)	$16,320	'

CONDENSED_CONSOLIDATED_STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited) (Parenthetical) (Treasury Stock - Common [Member])	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Treasury Stock - Common [Member]	'	'
Purchase of shares for company benefit plans, shares	24,859	249,498
Release of shares from company benefit plans, shares	369,432	151,153

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies (Note)	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block]	'
	Basis of Presentation and Summary of Significant Accounting Policies
	Basis of Presentation
	The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation (Chesapeake or the Company) and its subsidiaries were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. These financial statements were prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP.
	This Form 10-Q relates to the three and nine months ended September 30, 2014 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2013 (the “Prior Quarter” and the “Prior Period”, respectively). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2013 (“2013 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 presentation 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.

SpinOff_of_Oilfield_Services_B

Spin-Off of Oilfield Services Business (Note)	9 Months Ended
	Sep. 30, 2014
Discontinued Operations and Disposal Groups [Abstract]	'
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	'
	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 Chesapeake Oilfield Operating, L.L.C. (COO), into an independent, publicly traded company called Seventy Seven Energy Inc. (SSE). 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 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 13 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 described below, 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 connection with the spin-off, we entered into several agreements to define the terms and conditions of the spin-off and our ongoing relationship with SSE after the spin-off, including a master separation agreement, a tax sharing agreement, an employee matters agreement, a transition services agreement, a services agreement and certain commercial agreements. These agreements, among other things, allocate responsibility for obligations arising before and after the distribution date, including obligations relating to taxes, employees, various transition services and oilfield services.
	•	The master separation agreement sets forth the agreements between SSE and Chesapeake regarding the principal transactions that were necessary to effect the spin-off and also sets forth other agreements that govern certain aspects of SSE’s relationship with Chesapeake after completion of the spin-off.
	•	The tax sharing agreement governs the respective rights, responsibilities and obligations of SSE and Chesapeake with respect to tax liabilities and benefits, tax attributes, the preparation and filing of tax returns, the control of audits and other tax proceedings, and certain other matters regarding taxes.
	•	The employee matters agreement addresses employee compensation and benefit plans and programs, and other related matters in connection with the spin-off, including the treatment of holders of Chesapeake common stock options, restricted stock awards, restricted stock units and performance share units, and the cooperation between SSE and Chesapeake in the sharing of employee information and maintenance of confidentiality. See Note 8 for additional information regarding the effect of the spin-off on outstanding equity compensation.
	•	The transition services agreement sets forth the terms on which we provide SSE certain services. Transition services include marketing and corporate communication, human resources, information technology, security, legal, risk management, tax, environmental health and safety, maintenance, internal audit, accounting, treasury and certain other services specified in the agreement. SSE pays Chesapeake a negotiated fee for providing those services.
	•	The services agreement requires us to utilize, at market-based pricing, certain SSE pressure pumping services. See Note 5 for a summary of the terms of the services agreement.
	•	We have also entered into drilling agreements that are rig-specific daywork drilling contracts with terms ranging from three months to three years and at market-based rates. We have the right to terminate a drilling agreement in certain circumstances. As of September 30, 2014, the aggregate undiscounted minimum future payments under these drilling agreements were approximately $356 million.
	In the Current Period, our stockholders’ equity decreased by $270 million as the result of the spin-off, and we recognized $15 million of charges associated with the spin-off that are included in restructuring and other termination costs on our condensed consolidated statement of operations. See Note 15 for further details regarding these charges.

Earnings_Per_Share_Note

Earnings Per Share (Note)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]	'
Earnings Per Share Disclosure [Text Block]	'
	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 4 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 such shares, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended September 30, 2014:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	59
	5.75% cumulative convertible preferred stock (series A)	$	16	42
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	6
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	3
	Three Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	2
	Nine Months Ended September 30, 2014:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	59
	5.75% cumulative convertible preferred stock (series A)	$	47	42
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	6
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3
	Nine Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3

Debt_Note

Debt (Note)

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

'

Debt Disclosure [Text Block]

'

Debt

Our long-term debt consisted of the following as of September 30, 2014 and December 31, 2013:

September 30,

December 31,

2014

2013

($ in millions)

Term loan due 2017(a)

$

—

$

2,000

9.5% senior notes due 2015(b)

—

1,265

3.25% senior notes due 2016

500

500

6.25% euro-denominated senior notes due 2017(c)

435

473

6.5% senior notes due 2017

660

660

6.875% senior notes due 2018(d)

—

97

7.25% senior notes due 2018

669

669

Floating rate senior notes due 2019

1,500

—

6.625% senior notes due 2019(e)

—

650

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

—

5.75% senior notes due 2023

1,100

1,100

2.75% contingent convertible senior notes due 2035(f)

396

396

2.5% contingent convertible senior notes due 2037(f)

1,168

1,168

2.25% contingent convertible senior notes due 2038(f)

347

347

Corporate revolving bank credit facility

59

—

Oilfield services revolving bank credit facility(g)

—

405

Discount on senior notes and term loan(h)

(252

)

(357

)

Interest rate derivatives(i)

10

13

Total long-term debt, net

$

11,592

$

12,886

___________________________________________

(a)

In the Current Period, we repaid the borrowings outstanding under the term loan due 2017 with a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes issued in the Current Period.

(b)

In the Current Period, we completed a tender offer for and redemption of the 9.5% Senior Notes due 2015.

(c)

The principal amount shown is based on the exchange rate of $1.2631 to €1.00 and $1.3743 to €1.00 as of September 30, 2014 and December 31, 2013, respectively. See Note 9 for information on our related foreign currency derivatives.

(d)

In the Current Period, we redeemed all outstanding 6.875% Senior Notes due 2018.

(e)

Initial issuers were COO and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In the Current Period, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our condensed consolidated balance sheet. See Note 2 for further discussion of the spin-off.

(f)

The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:

Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.

Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the third quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2014 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 in 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 such 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 the dividend of SSE common stock paid in the spin-off of our oilfield services business and 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

Holders' Demand

Common Stock

Contingent Interest

Convertible

Repurchase Dates

Price Conversion

First Payable

Senior  Notes

Thresholds

(if applicable)

2.75% due 2035

November 15, 2015, 2020, 2025, 2030

$

45.22

May 14, 2016

2.5% due 2037

May 15, 2017, 2022, 2027, 2032

$

59.71

November 14, 2017

2.25% due 2038

December 15, 2018, 2023, 2028, 2033

$

100.45

June 14, 2019

Optional Redemption by the Company. We may redeem the 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.

(g)

In the Current Period, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 2 for further discussion of the spin-off.

(h)

Discount as of September 30, 2014 and December 31, 2013 included $244 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan discussed below.

(i)

See Note 9 for further discussion related to these instruments.

Term Loan

In November 2012, we established an unsecured five-year term loan credit facility in an aggregate principal amount of $2.0 billion for net proceeds of $1.935 billion. The term loan provided that it could be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The maturity date of the term loan was December 2, 2017. In the Current Period, we used a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. We recorded a loss of $90 million, consisting of $40 million in premiums, $30 million of unamortized discount and $20 million of unamortized deferred charges, in connection with the termination.

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 and 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.

During the Current Period, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We used the remaining proceeds along with cash on hand to redeem the remaining $97 million principal amount of the 6.875% Senior Notes due 2018 and to purchase and redeem the remaining $1.265 billion principal amount of the 9.5% Senior Notes due 2015 for $1.454 billion. We recorded a loss of approximately $6 million associated with the redemption of the 6.875% Senior Notes due 2018, which consisted of $5 million in premiums and $1 million of unamortized deferred charges. We recorded a loss of approximately $99 million associated with the purchase and redemption of the 9.5% Senior Notes due 2015, which consisted of $87 million in premiums, $9 million of unamortized discount and $3 million of unamortized deferred charges.

During the Prior Period, we issued $2.3 billion in aggregate principal amount of senior notes at par. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our corporate revolving bank credit facility and purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers during the Prior Period. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During the Prior Period, we also redeemed $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the 2019 Notes) at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, our redemption of the 2019 notes has been the subject of litigation. On July 15, 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.

In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York (the Court) against The Bank of New York Mellon Trust Company, N.A. (BNY Mellon), the indenture trustee for the 2019 Notes. The Company sought a declaration that the notice it issued to redeem all of the 2019 Notes at par (plus accrued interest through the redemption date) was timely and effective pursuant to the special early redemption provision of the supplemental indenture governing the 2019 Notes. BNY Mellon asserted that the notice was not effective to redeem the 2019 Notes at par because it was not timely for that purpose and because of the specific phrasing in the notice that provided it would not be effective unless the Court concluded it was timely. The Court conducted a trial on the matter and ruled in the Company’s favor in May 2013. BNY Mellon filed notice of an appeal of the decision with the United States Court of Appeals for the Second Circuit and the appeal is currently pending.

No scheduled principal payments are required on our senior notes until 2016 unless the holders of our 2.75% Contingent Convertible Senior Notes due 2035 exercise their individual demand repurchase rights on November 15, 2015, which would require us to repurchase all or a portion of the $396 million principal amount of notes.

Corporate Credit Facility

We have a $4.0 billion syndicated revolving bank credit facility that matures in December 2015. Our subsidiaries Chesapeake Exploration, L.L.C., Chesapeake Appalachia, L.L.C. and Chesapeake Louisiana, L.P. are borrowers under the facility. As of September 30, 2014, we had $59 million of outstanding borrowings under the facility and utilized $15 million of the facility for various letters of credit. Borrowings under the facility are secured by proved reserves and bear interest at our option at either (i) the greater of the reference rate of Union Bank, N.A. or the federal funds effective rate plus 0.50%, both of which are subject to a margin that varies from 0.50% to 1.25% per annum according to our senior unsecured long-term debt ratings, or (ii) the Eurodollar rate, which is based on LIBOR, plus a margin that varies from 1.50% to 2.25% per annum according to our senior unsecured long-term debt ratings. The collateral value and borrowing base are determined periodically. The unused portion of the facility is subject to a commitment fee of 0.50% per annum. Interest is payable quarterly or, if LIBOR applies, may be payable at more frequent intervals. Although the applicable interest rates under the facility fluctuate based on our long-term senior unsecured credit ratings, the facility does not contain provisions which would trigger an acceleration of amounts due under the facility or a requirement to post additional collateral in the event of a downgrade of our credit ratings.

Our corporate credit facility agreement contains various covenants and restrictive provisions which limit our ability to incur additional indebtedness, make investments or loans and create liens and require us to maintain an indebtedness to total capitalization ratio and an indebtedness to EBITDA ratio, in each case as defined in the agreement. We were in compliance with all covenants under our corporate credit facility agreement as of September 30, 2014.

Our corporate credit facility is fully and unconditionally guaranteed, on a joint and several basis, by Chesapeake and certain of our wholly owned subsidiaries. If we should fail to perform our obligations under the credit facility agreement, the revolving credit commitment could be terminated and any outstanding borrowings under the facility could be declared immediately due and payable. Such acceleration, if involving a principal amount of $50 million or more, would constitute an event of default under our senior note and contingent convertible senior note indentures, which could in turn result in the acceleration of a significant portion of such indebtedness. The credit facility agreement also has cross default provisions that apply to our secured hedging facility and other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $125 million. In addition, the facility contains a restriction on our ability to declare and pay cash dividends on our common or preferred stock if an event of default has occurred.

Spin-Off Debt Transactions

Prior to the spin-off of our oilfield services business, 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 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 condensed consolidated balance sheet as of June 30, 2014. See Note 2 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 currently consists of our corporate credit facility and as of December 31, 2013 also consisted of our former oilfield services credit facility and term loan, 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.

30-Sep-14

31-Dec-13

Carrying

Estimated

Carrying

Estimated

Amount

Fair Value

Amount

Fair Value

($ in millions)

Long-term debt (Level 1)

$

11,523

$

12,347

$

10,501

$

11,557

Long-term debt (Level 2)

$

59

$

58

$

2,372

$

2,369

Contingencies_and_Commitments_

Contingencies and Commitments (Note)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies Disclosure [Text Block]	'
	Contingencies and Commitments
	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. Final judgment in favor of Chesapeake and the officer and director defendants was entered on June 21, 2013, and the plaintiff filed a notice of appeal on July 19, 2013 in the U.S. Court of Appeals for the Tenth Circuit. On August 8, 2014, the District Court dismissal was affirmed by the Court of Appeals, and on September 8, 2014, the plaintiff filed a petition for rehearing. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with this matter.
	Shareholder Derivative Litigation. A derivative action relating to the July 2008 offering filed in the U.S. District Court for the Western District of Oklahoma on September 6, 2011 is pending. Following the denial on September 28, 2012 of defendants’ motion to dismiss and pursuant to court order, nominal defendant Chesapeake filed an answer in the case on October 12, 2012. By stipulation between the parties, the case is stayed pending final resolution of the above described appeal.
	A federal consolidated derivative action and an Oklahoma state court derivative action have been stayed since 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, the parties have stipulated to continue the stay of the Oklahoma state court derivative action while plaintiffs pursue their claims in the federal consolidated derivative action. Plaintiffs’ consolidated amended derivative complaint was filed on October 31, 2014, and the Company intends to file a motion to dismiss by December 5, 2014.
	On May 8, 2012, a derivative action was filed in the District Court of Oklahoma County, Oklahoma against the Company's directors alleging breaches of fiduciary duties and corporate waste related to the Company's officers and directors' use of the Company's fractionally owned corporate jets. On August 21, 2012, the District Court granted the Company's motion to dismiss for lack of derivative standing, and the plaintiff appealed the ruling on December 6, 2012. On May 16, 2014, the Court of Civil Appeals for the State of Oklahoma affirmed the dismissal. On July 7, 2014, plaintiffs filed a petition for writ of certiorari in the Oklahoma Supreme Court seeking review of the Court of Civil Appeals’ decision, and on October 13, 2014, the petition for certiorari was denied.
	On April 10, 2014, a derivative action was filed in the District Court of Oklahoma County, Oklahoma against current and former directors and officers of the Company alleging, among other things, breach of fiduciary duties, waste of corporate assets, gross mismanagement and unjust enrichment related to the Company’s payment of shareholder dividends since October 2012. On July 2, 2014, the Company filed a motion to dismiss. The plaintiffs voluntarily dismissed the action on October 31, 2014.
	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 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 89th 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, alleges that Chesapeake’s conduct in canceling lease offers to Michigan landowners in 2010 violated the state’s criminal enterprises and false pretenses felony statutes. On September 9, 2014, following a preliminary hearing, the Court ruled that all charges in the complaint would be tried. No trial date has been set for either matter.
	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 natural gas and oil 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 our consolidated financial position, results of operations or cash flows. In addition, as described above, the Michigan Attorney General has commenced a criminal proceeding against us based on lease offers to Michigan landowners in 2010.
	Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits against us allege, among other things, that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. 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 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 2010 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 have participated in mediation concerning the claims asserted in the putative class action litigation. Based on analysis we and outside advisors have conducted, we have accrued a loss contingency of $100 million in the Current Quarter condensed consolidated statement of operations. Although we believe our estimate of the potential loss is reasonable, the final resolution of the Oklahoma royalty claims could differ from the amount accrued, and actual results, whether by continued litigation or settlement, could differ materially from management’s estimate.
	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. In Pennsylvania, two putative statewide class actions and one purported class arbitration were filed in 2014 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 Pennsylvania cases include claims for violation of and conspiracy to violate the federal Racketeer Influenced and Corrupt Organizations Act. 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 natural gas and oil 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
	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 natural gas, oil and NGL sales prices used in our proved reserves estimates.
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
		September 30, 2014
		($ in millions)
	2014	$	616
	2015	1,852
	2016	1,933
	2017	1,951
	2018	1,748
	2019 - 2099	7,672
	Total	$	15,772
	Drilling Contracts
	We have contracts with various drilling contractors, including those with SSE as discussed in Note 2, to utilize drilling services with terms ranging from three months to three years at market based pricing. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2014, the aggregate undiscounted minimum future payments under these drilling service commitments were approximately $449 million.
	Pressure Pumping Contracts
	As discussed in Note 2, in connection with the spin-off of our oilfield services business we entered into an agreement with a subsidiary of SSE related to pressure pumping services. The services agreement requires us to utilize, at market-based pricing, the lesser of (i) seven, five and three pressure pumping crews in years one, two and three of the agreement, respectively, or (ii) 50% of the total number of all pressure pumping crews working for us in all of our operating regions during the respective year. We are also required to utilize SSE pressure pumping services for a minimum number of fracture stages as set forth in the agreement. We are entitled to terminate the agreement in certain situations, including if SSE fails to provide the overall quality of service provided by similar service providers. As of September 30, 2014, the aggregate undiscounted minimum future payments under this agreement were approximately $283 million.
	Drilling Commitments
	We have committed to drill wells in conjunction with our CHK Cleveland Tonkawa, L.L.C. financial transaction and in conjunction with the formation of the Chesapeake Granite Wash Trust. See Noncontrolling Interests in Note 7 for discussion of these commitments.
	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 10 for further discussion of our VPP transactions.
	Net Acreage Maintenance Commitments
	Under the terms of our joint venture agreements with Total and Sinopec (see Note 10), 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. To date, we have satisfied our replacement commitments under the Sinopec agreement. In the Current Quarter, we settled a dispute with Total regarding our acreage maintenance obligation as of December 31, 2012 for $50 million. The payment was based on a shortfall of approximately 20,800 net acres.
	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 September 30, 2014, 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 11 for further discussion of this investment.
	As part of our normal course of business, we enter into various agreements providing, or otherwise arranging, 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. 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 the consummation of 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 natural gas and oil 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 such interests have been created, we have the responsibility to bear the cost of developing and producing the reserves attributable to such interests. See Note 10 for further discussion of our VPP transactions.

Other_Liabilities_Note

Other Liabilities (Note)	9 Months Ended
	Sep. 30, 2014
Other Liabilities Disclosure [Abstract]	'
Other Liabilities Disclosure [Text Block]	'
	Other Liabilities
	Other current liabilities as of September 30, 2014 and December 31, 2013 are detailed below.
			September 30,		December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,401	$	1,409
	Accrued natural gas, oil and NGL drilling and production costs		389		457
	Joint interest prepayments received		382		464
	Accrued compensation and benefits		250		320
	Other accrued taxes		115		161
	Accrued dividends		102		101
	Other		496		599
	Total other current liabilities		$	3,135	$	3,511
	Other long-term liabilities as of September 30, 2014 and December 31, 2013 are detailed below.
			September 30,		December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	227	$	250
	CHK C-T ORRI conveyance obligation(b)		139		149
	Financing obligations		30		31
	Unrecognized tax benefits		55		317
	Other		236		237
	Total other long-term liabilities		$	687	$	984
	____________________________________________
	(a)	$13 million and $13 million of the total $240 million and $263 million obligations are recorded in other current liabilities as of September 30, 2014 and December 31, 2013, respectively. See Noncontrolling Interests in Note 7 for further discussion of the transaction.
	(b)	$21 million and $12 million of the total $160 million and $161 million obligations are recorded in other current liabilities as of September 30, 2014 and December 31, 2013, respectively. See Noncontrolling Interests in Note 7 for further discussion of the transaction.

Equity_Note

Equity (Note)	9 Months Ended
	Sep. 30, 2014
Equity [Abstract]	'
Stockholders' Equity Note Disclosure [Text Block]	'
	Equity
	Common Stock
	The following is a summary of the changes in our common shares issued during the Current Period and the Prior Period:
			Nine Months Ended
			September 30,
			2014			2013
			(in thousands)
	Shares issued as of January 1		666,192			666,468
	Restricted stock issuances (net of forfeitures)(a)		(2,413	)		684
	Stock option exercises		1,267			321
	Shares issued as of September 30		665,046			667,473
	___________________________________________
	(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 restricted shares of common stock are issued on the grant date of RSAs. We refer to RSAs and RSUs collectively as restricted stock.
	Preferred Stock
	The following reflects the shares outstanding during the Current Period and the Prior Period and the liquidation preferences of our cumulative convertible preferred stock:
			5.75%				5.75% (A)				4.50%			5.00%
														(2005B)
	Shares outstanding as of January 1, 2014 and 2013 and		1,497				1,100				2,559			2,096
	September 30, 2014 and 2013 (in thousands)
	Liquidation preference per share		$	1,000			$	1,000			$	100		$	100
	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 will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
	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.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		3				—				3
	Amounts reclassified from accumulated other comprehensive income		13				(5		)		8
	Net other comprehensive income		16				(5		)		11
	Balance, September 30, 2014		$	(151	)		$	—			$	(151	)
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		13				4				17
	Net other comprehensive income		15				(2		)		13
	Balance, September 30, 2013		$	(174	)		$	5			$	(169	)
	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		Affected Line Item		Three Months Ended
	Other Comprehensive		in the Statement		September 30,
	Income (Loss) Components		Where Net Income is Presented		2014				2013
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	3			$	2
	Investments:
	Sale of investment		Net gain on sale of investment		—				(2		)
	Total reclassifications for the period, net of tax				$	3			$	—
	Details About Accumulated		Affected Line Item		Nine Months Ended
	Other Comprehensive		in the Statement		September 30,
	Income (Loss) Components		Where Net Income is Presented		2014				2013
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	13			$	13
	Investments:
	Impairment of investment		Losses on investments		—				6
Sale of investment		Net gain on sale of investment		(5		)		(2		)
Total reclassifications for the period, net of tax				$	8			$	17
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 natural gas and oil assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate 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 (the CHK C-T LLC 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. Pursuant to the CHK C-T LLC Agreement, 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 September 30, 2014 and December 31, 2013, was reflected as restricted cash 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. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement. Any such optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares unless we have not met our drilling commitment at such time, in which case an optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of September 30, 2014 and December 31, 2013, the redemption price and the liquidation preference were approximately $1,200 and $1,245, respectively, per preferred share.
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 12.5 net wells in each of the six-month periods ending June 30, 2014 and December 31, 2014. If we fail to meet the then-current cumulative drilling commitment in any six-month period, any optional cash distributions would be distributed 100% to the investors. If we fail to meet the then-current cumulative drilling commitment in two consecutive six-month periods, the then-applicable internal rate of return to investors at redemption would increase by 3% per annum. In addition, if we fail to meet the then-current cumulative drilling commitment in four consecutive six-month periods, the then-applicable internal rate of return to investors at redemption would be increased by an additional 3% per annum. Any such increase in the internal rate of return would be effective only until the end of the first succeeding six-month period in which we have met our then-current cumulative drilling commitment. CHK C-T is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. Under the development agreement, approximately 13 and 74 qualified net wells were added in the Current Period and the Prior Period, respectively. Through September 30, 2014, we had met all current drilling commitments associated with the CHK C-T transaction.
The CHK C-T investors’ right to receive, proportionately, a 3.75% ORRI in the contributed wells and up to 1,000 future net wells on our contributed leasehold 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, which runs from 2012 through the first quarter of 2025. However, in no event would we be required to deliver to investors more than a total ORRI of 3.75% in existing wells and 1,000 future net wells. If at any time CHK C-T holds fewer net acres than would enable us to drill all then-remaining net wells on 160-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 such remaining ORRIs. CHK C-T retains the right to repurchase the investors’ right to receive ORRIs in the remaining net wells at the then-current fair market value of such remaining ORRIs once we have drilled a minimum of 867 net wells. The obligation to deliver future ORRIs has been recorded as a liability which 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 natural gas and oil properties. We had met our ORRI conveyance commitment as of December 31, 2013, but we do not anticipate meeting the 2014 ORRI conveyance commitment.
As of September 30, 2014 and December 31, 2013, $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets were attributable to CHK C-T. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of $19 million, $19 million, $56 million and $56 million, respectively, was attributable to the noncontrolling interests of CHK C-T.
Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale natural gas and oil 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 the Current Quarter, 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 is 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 from 2012 through 2023. However, in no event would we be 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 such 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 such remaining ORRIs once we have drilled a minimum of 1,300 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 natural gas and oil 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 the 2013 ORRI conveyance commitment as of December 31, 2013, and through September 30, 2014, we were on target to meet the 2014 ORRI conveyance commitments associated with the CHK Utica transaction.
As of September 30, 2014 and December 31, 2013, $0 and $807 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to CHK Utica. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of approximately $6 million, $19 million, $43 million and $60 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 initial public offering of the Trust, 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 that may be recovered by the Trust under such lien could not exceed $263 million initially and is proportionately reduced as we fulfill our drilling obligation over time. As of September 30, 2014 and 2013, we had drilled or caused to be drilled approximately 95 and 80 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $51 million and $85 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 such quarter. If there is not sufficient cash to fund such a distribution on all of the Trust units, the distribution to be made with respect to the subordinated units will be reduced or eliminated for such 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 seven quarters of distributions paid. 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 such quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. Through September 30, 2014, 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 such 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				Cash Distribution
				per				per
				Common Unit				Subordinated Unit
March 2014 - May 2014		August 29, 2014		$	0.5796			$	—
December 2013 - February 2014		May 30, 2014		$	0.6454			$	—
September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
We have determined that the Trust is a variable interest entity (VIE) and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our condensed consolidated financial statements. As of September 30, 2014 and December 31, 2013, $291 million and $314 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to the Trust. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of approximately $6 million, $2 million, $14 million and $14 million, respectively, was attributable to the Trust’s noncontrolling interests in our condensed consolidated statements of operations. See Note 12 for further discussion of VIEs.
Wireless Seismic, Inc. We have a controlling 52% equity interest in Wireless Seismic, Inc. (Wireless), a privately owned company engaged in research, development and production of wireless seismic systems and related technology that deliver seismic information obtained from standard geophones in real time to laptop and desktop computers. As of September 30, 2014 and December 31, 2013, $6 million and $9 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to Wireless. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, losses of $1 million, $1 million, $3 million and $3 million, respectively, were attributable to noncontrolling interests of Wireless in our condensed consolidated statements of operations.

ShareBased_Compensation_Note

Share-Based Compensation (Note)	9 Months Ended
	Sep. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Disclosure of Compensation Related Costs, Share-based Payments [Text Block]	'
	Share-Based Compensation
	Chesapeake’s share-based compensation program consists of restricted stock (including RSAs and RSUs), stock options and performance share units (PSUs) granted to employees 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 on unvested shares. A summary of the changes in unvested shares of restricted stock during the Current Period is presented below.
			Number of			Weighted Average
			Unvested			Grant Date
			Restricted Shares			Fair Value
			(in thousands)
	Unvested shares as of January 1, 2014		13,400			$	23.38
	Granted		4,882			$	26.09
	Vested		(4,557	)		$	27.58
	Forfeited		(3,279	)		$	28.72
	Unvested shares as of September 30, 2014		10,446			$	21.14
	The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $126 million based on the stock price at the time of vesting.
	As of September 30, 2014, there was $160 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 2.2 years.
	The vesting of certain restricted stock grants may result in state and federal income tax benefits, or reductions in such 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 $4 million and $1 million, respectively, and during the Prior Quarter and the Prior Period, we recognized reductions in tax benefits related to restricted stock of a nominal amount and $12 million, respectively. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
	Stock Options. In the Current Period and the Prior Period, we granted members of senior management stock options that vest ratably over a three-year period. In January 2013, we also granted retention awards to certain officers of stock options that vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.
	We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the simplified method, as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy, over the expected life of the option. The Company used the following weighted average assumptions to estimate the grant date fair value of the stock options granted in the Current Period:
	Expected option life - years		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
	The following table provides information related to stock option activity during the Current Period:
			Number of			Weighted			Weighted		Aggregate
			Shares			Average			Average		Intrinsic
			Underlying			Exercise			Contract		Value(a)
			Options			Price			Life in
						Per Share			Years
			(in thousands)								($ in millions)
	Outstanding at January 1, 2014		5,268			$	19.28		6.66		$	41
	Granted		994			$	24.43
	Exercised		(1,309	)		$	18.75				$	11
	Expired		(28	)		$	18.97
	Forfeited		(313	)		$	21.05
	Outstanding at September 30, 2014		4,612			$	19.53		7.63		$	17
	Exercisable at September 30, 2014		1,133			$	18.71		6.78		$	5
	___________________________________________
	(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
	As of September 30, 2014, there was $14 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 1.9 years.
	The vesting of certain stock option grants may result in state and federal income tax benefits, or reductions in such benefits, related to the difference between the market price of the common stock at the date of vesting and the date of grant. During both the Current Quarter and the Current Period, we recognized a reduction in tax benefits related to stock options of a nominal amount. During both the Prior Quarter and the Prior Period, we recognized excess tax benefits related to stock options of $2 million. Each adjustment was recorded to additional paid-in capital and deferred income taxes.
	Restricted Stock and Stock Option Compensation. We recognized the following compensation costs related to restricted stock and stock options during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended							Nine Months Ended
			September 30,							September 30,
			2014				2013			2014				2013
			($ in millions)
	General and administrative expenses		$	12			$	13		$	36			$	48
	Natural gas and oil properties		6				12			22				45
	Natural gas, oil and NGL production expenses		5				5			13				17
	Marketing, gathering and compression expenses		2				2			5				5
	Oilfield services expenses		—				3			5				8
	Total		$	25			$	35		$	81			$	123
	Liability-Classified Awards
	Performance Share Units. In 2012, 2013 and 2014, we granted PSUs to senior management that settle in cash at the end of their respective performance periods and vest ratably over their respective terms. The 2012 awards were granted in one-, two- and three-year tranches and are settled in cash on the first, second and third anniversary dates of the awards, and the 2013 and 2014 awards 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, the achievement of operational performance goals such as production and proved reserve growth.
	For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125% resulting in a maximum total payout of 250%. For PSUs granted in 2013, the TSR component can range from 0% to 125% 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 the 2013 and 2014 PSUs, the payout percentage is capped at 100% if the Company’s absolute TSR is less than zero. The PSU grants are recognized over the service period. The number of units settled is dependent upon the Company’s estimates of the underlying performance measures. For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and used the following assumptions to determine the grant date fair value of the PSUs granted in the Current Period:
	Volatility		41.37	%
	Risk-free interest rate		0.76	%
	Dividend yield for value of awards		1.36	%
	The following table presents a summary of our PSU awards as of September 30, 2014:
			Units			Fair Value			Fair Value				Liability for
						as of							Vested
						Grant Date							Amount
						($ in millions)
	2012 Awards (a)
Payable 2015		884,507			$	23		$	21			$	21
2013 Awards
Payable 2016		1,701,941			$	35		$	45			$	42
2014 Awards
Payable 2017		609,637			$	16		$	10			$	6
___________________________________________
(a)	In the Current Period and the Prior Period, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
PSU Compensation. We recognized the following compensation costs related to PSUs during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
		Three Months Ended							Nine Months Ended
		September 30,							September 30,
		2014				2013			2014				2013
		($ in millions)
General and administrative expenses		$	(12	)		$	18		$	(2	)		$	28
Natural gas and oil properties		—				4			3				8
Natural gas, oil and NGL production expenses		—				1			—				2
Marketing, gathering and compression expenses		(1		)		2			—				3
Total		$	(13	)		$	25		$	1			$	41
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 2) addresses the treatment of holders of Chesapeake stock options, restricted stock and performance share units. 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_Activit

Derivative and Hedging Activities (Note)	9 Months Ended
	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative and Hedging Activities Disclosure [Text Block]	'
	Derivative and Hedging Activities
	Chesapeake uses commodity derivative instruments to secure attractive pricing and margins on 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 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.
	Natural Gas and Oil Derivatives
	As of September 30, 2014 and December 31, 2013, our natural gas and oil 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 such excess on sold call options, and Chesapeake receives such 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.
	•	Swaptions: Chesapeake sells call swaptions in exchange for a premium that allows a counterparty, on a specific date, to enter into a fixed-price swap for a certain period of time.
	•	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 natural gas and oil derivative instrument assets (liabilities) as of September 30, 2014 and December 31, 2013 are provided below.
			30-Sep-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		224			$	27			448			$	(23	)
	Three-way collars		278			41				288			(7		)
	Collars		11			5				—			—
	Call options		193			(183		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		95			(2		)		68			3
	Total natural gas		801			(112		)		1,009			(237		)
	Oil (mmbbl):
	Fixed-price swaps		19.6			113				25.3			(50		)
	Three-way collars		4.4			11				—			—
	Call options		38.3			(179		)		42.5			(265		)
	Basis protection swaps		0.1			—				0.4			1
	Total oil		62.4			(55		)		68.2			(314		)
	Total estimated fair value					$	(167	)					$	(551	)
	We have terminated certain commodity derivative contracts that were previously designated as cash flow hedges for which the hedged production is still expected to occur. See further discussion below under Effect of Derivative Instruments - Accumulated Other Comprehensive Income (Loss).
	Interest Rate Derivatives
	As of September 30, 2014 and December 31, 2013, 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 derivative liabilities as of September 30, 2014 and December 31, 2013 was $1.450 billion and $2.250 billion, respectively. The estimated fair value of our interest rate derivative liabilities as of September 30, 2014 and December 31, 2013 was $52 million and $98 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 $10 million in net gains related to such 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 sheet as a liability of $30 million and an asset of $2 million as of September 30, 2014 and December 31, 2013, respectively. The euro-denominated debt in long-term debt has been adjusted to $435 million as of September 30, 2014 using an exchange rate of $1.2631 to €1.00.
	Effect of Derivative Instruments – Condensed Consolidated Balance Sheets
	The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 on a gross basis and after same-counterparty netting:
			September 30, 2014
	Balance Sheet Classification		Gross Fair Value				Amounts Netted				Net Fair Value Presented
							in Condensed Consolidated				in Condensed Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	Commodity Contracts
	Short-term derivative asset		$	193			$	(93	)		$	100
	Long-term derivative asset		26				(12		)		14
	Short-term derivative liability		(155		)		93				(62		)
	Long-term derivative liability		(231		)		12				(219		)
	Total commodity contracts		(167		)		—				(167		)
	Interest Rate Contracts
	Short-term derivative liability		(7		)		—				(7		)
	Long-term derivative liability		(45		)		—				(45		)
	Total interest rate contracts		(52		)		—				(52		)
	Foreign Currency Contracts(a)
	Long-term derivative liability		(30		)		—				(30		)
	Total foreign currency contracts		(30		)		—				(30		)
	Total Derivatives		$	(249	)		$	—			$	(249	)
			December 31, 2013
	Balance Sheet Classification		Gross Fair Value				Amounts Netted				Net Fair Value Presented
							in Condensed Consolidated				in Condensed Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	Commodity Contracts
	Short-term derivative asset		$	29			$	(29	)		$	—
Long-term derivative asset		11				(9		)		2
Short-term derivative liability		(231		)		29				(202		)
Long-term derivative liability		(362		)		9				(353		)
Total commodity contracts		(553		)		—				(553		)
Interest Rate Contracts
Short-term derivative liability		(6		)		—				(6		)
Long-term derivative liability		(92		)		—				(92		)
Total interest rate contracts		(98		)		—				(98		)
Foreign Currency Contracts(a)
Long-term derivative asset		2				—				2
Total foreign currency contracts		2				—				2
Total Derivatives		$	(649	)		$	—			$	(649	)
____________________________________________
(a)	Designated as cash flow hedging instruments.
As of September 30, 2014 and December 31, 2013, we did not have any cash collateral balances for these derivatives.
Effect of Derivative Instruments – Condensed Consolidated Statements of Operations
The components of natural gas, oil and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		($ in millions)
Natural gas, oil and NGL sales		$	1,777			$	1,839			$	5,842			$	5,303
Gains (losses) on undesignated natural gas and oil		569				(250		)		(5		)		162
derivatives
Losses on terminated cash flow hedges		(5		)		(3		)		(25		)		(21		)
Total natural gas, oil and NGL sales		$	2,341			$	1,586			$	5,812			$	5,444
The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2014				2013				2014				2013
		($ in millions)
Interest expense on senior notes		$	170			$	180			$	534			$	560
Interest expense on term loans		—				29				36				87
Amortization of loan discount, issuance costs and other		9				21				44				70
Interest expense on credit facilities		6				8				22				30
Gains on terminated fair value hedges		—				—				(2		)		—
(Gains) losses on undesignated interest rate derivatives		2				(3		)		(48		)		51
Capitalized interest		(170		)		(195		)		(504		)		(634		)
Total interest expense		$	17			$	40			$	82			$	164
Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Three Months Ended
		September 30,
		2014								2013
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
Balance, beginning of period		$	(243	)		$	(154	)		$	(286	)		$	(178	)
Net change in fair value		—				—				3				2
Gains reclassified to income		5				3				3				2
Balance, end of period		$	(238	)		$	(151	)		$	(280	)		$	(174	)
		Nine Months Ended
		September 30,
		2014								2013
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)
Net change in fair value		6				3				3				2
Losses reclassified to income		25				13				21				13
Balance, end of period		$	(238	)		$	(151	)		$	(280	)		$	(174	)
Approximately $147 million of the $151 million of accumulated other comprehensive loss as of September 30, 2014 represents 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. These amounts will be recognized in earnings in the month in which the originally forecasted hedged production occurs. As of September 30, 2014, we expect to transfer approximately $26 million of net loss included in accumulated other comprehensive income to net income during the next 12 months. The remaining amounts will be transferred by December 31, 2022.
Credit Risk Considerations
Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of September 30, 2014, our natural gas, oil and interest rate derivative instruments were spread among 18 counterparties.
Hedging Facility
Our secured commodity hedging facility with 17 counterparties provides approximately 1.031 bboe of hedging capacity for natural gas, oil and NGL price derivatives and 1.031 bboe for basis derivatives with an aggregate mark-to-market capacity of $16.5 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 corporate revolving bank 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 to Chesapeake exceed defined thresholds. As of September 30, 2014, we had hedged under the facility 178 mmboe of our future production with price derivatives and 16 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 natural gas and oil 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 natural gas, oil, interest rate and cross currency swaps do not include optionality and therefore generally have no unobservable inputs, they are classified as Level 2. All other derivatives have some level of unobservable input, such as volatility curves, and are therefore classified as Level 3. Derivatives are also subject to the risk that either party to a contract will be unable to meet its obligations. We factor non-performance risk into the valuation of our derivatives using current published credit default swap rates. To date, this has not had a material impact on the values of our derivatives.
The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
		Quoted				Significant				Significant				Total
		Prices in				Other				Unobservable				Fair Value
		Active				Observable				Inputs
		Markets				Inputs				(Level 3)
		(Level 1)				(Level 2)
						($ in millions)
As of September 30, 2014
Derivative Assets (Liabilities):
Commodity assets		$	—			$	162			$	57			$	219
Commodity liabilities		—				(26		)		(362		)		(388		)
Interest rate liabilities		—				(52		)		—				(52		)
Foreign currency liability		—				(30		)		—				(30		)
Total derivatives		$	—			$	54			$	(305	)		$	(251	)
As of December 31, 2013
Derivative Assets (Liabilities):
Commodity assets		$	—			$	25			$	15			$	40
Commodity liabilities		—				(100		)		(493		)		(593		)
Interest rate liabilities		—				(98		)		—				(98		)
Foreign currency assets		—				2				—				2
Total derivatives		$	—			$	(171	)		$	(478	)		$	(649	)
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.
		Derivatives
		Commodity				Interest Rate
		($ in millions)
Beginning Balance as of January 1, 2014		$	(478	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		53				—
Total purchases, issuances, sales and settlements:
Settlements		124				—
Transfers(b)		(4		)		—
Ending Balance as of September 30, 2014		$	(305	)		$	—
Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		338				(1		)
Total purchases, issuances, sales and settlements:
Sales		—				1
Settlements		93				—
Ending Balance as of September 30, 2013		$	(585	)		$	—
___________________________________________
(a)		Natural Gas, Oil and								Interest Expense
		NGL Sales
		2014				2013				2014				2013
		($ in millions)
Total gains (losses) included in earnings for the period		$	53			$	338			$	—			$	(1	)
Change in unrealized gains (losses) related to		$	60			$	327			$	—			$	—
assets still held at reporting date
(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 natural gas and oil, market volatility and credit risk of counterparties. Changes in these inputs impact the fair value measurement of our derivative contracts. For example, an increase (decrease) in the forward prices and volatility of natural gas and oil prices decreases (increases) the fair value of natural gas and oil derivatives and adverse changes to our counterparties’ creditworthiness decreases the fair value of our derivatives. The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of September 30, 2014:
Instrument		Unobservable		Range		Weighted		Fair Value
Type		Input				Average		September 30, 2014(a)
								($ in millions)
Oil trades		Oil price volatility curves		12.45% - 20.94%		15.96%		$	(168	)
Natural gas trades		Natural gas price volatility		19.02% - 52.92%		28.47%		$	(137	)
		curves
___________________________________________
(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_T

Natural Gas and Oil Property Transactions (Note)	9 Months Ended
	Sep. 30, 2014
Property, Plant and Equipment [Abstract]	'
Mergers, Acquisitions and Dispositions Disclosure [Text Block]	'
	Natural Gas and Oil Property Transactions
	In the Current Quarter, we exchanged interests in approximately 440,000 gross acres in the Powder River Basin in southeastern Wyoming with RKI Exploration & Production, LLC (RKI). Under the agreement, we conveyed to RKI approximately 137,000 net acres and our interest in 67 gross wells with an average working interest of approximately 22% in the northern portion of the Powder River Basin, where RKI is currently designated operator. In exchange, RKI conveyed to us approximately 203,000 net acres and its interest in 186 gross wells with an average working interest of 48% in the southern portion of the Powder River Basin, where we are currently designated operator. In addition to the exchange, we paid RKI approximately $450 million in cash.
	During the Current Quarter, we sold noncore leasehold interests in the Marcellus Shale to Rice Drilling B LLC, a wholly owned subsidiary of Rice Energy Inc. (NYSE:RICE) for net proceeds of $233 million.
	During the Current Quarter, we sold noncore leasehold interests, producing properties and 61 wellhead compressor units in South Texas to Hilcorp Energy Company for net proceeds of $133 million. Operating obligations related to VPP #5 were also transferred. See Volumetric Production Payments below.
	During the Prior Quarter, we sold noncore leasehold interests and producing properties in the Haynesville Shale to EXCO Operating Company, L.P. (EXCO) for net proceeds of approximately $257 million.
	During the Prior Quarter, we sold noncore leasehold interests and producing properties in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million.
	During the Current Period and the Prior Period, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $335 million and $800 million, respectively, related to the divestiture of various other natural gas and oil properties.
	Under full cost accounting rules, we have accounted for the sale of natural gas and oil 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 Copper & Gold (formerly known as Plains Exploration & Production Company), pursuant to which we sold portions ranging from 20% to 50% of certain leasehold, producing properties and other assets located in eight different resource plays. In return, we received aggregate cash proceeds of $8.0 billion and commitments by our joint venture partners to pay, in the aggregate, our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. Each joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner and, if applicable, pays a specified percentage of our drilling and completion costs in designated wells. As of September 30, 2014, we had utilized all drilling carries from our joint venture partners except for Total’s remaining $195 million commitment to pay 60% of our drilling and completion costs for wells drilled in the Utica Shale play. We fully expect to use this drilling carry commitment prior to its expiration in December 2018.
	During the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $535 million and $669 million, respectively, in drilling and completion carries paid by our joint venture partners.
	During the Prior Period, we entered into a joint venture with Sinopec in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres in the Mississippian Lime play in northern Oklahoma for $949 million, excluding $71 million of net proceeds expected to be received pursuant to certain post-closing adjustments and approximately $90 million received at closing for closing adjustments. There was no drilling and completion carry associated with this transaction. In addition, during the Current Period and the Prior Period, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Eagle Ford and Mid-Continent plays to our joint venture partners for approximately $24 million and $48 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 natural gas and oil 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 have novated hedges to each of the respective VPP buyers and such 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 such interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods such 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 such 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 natural gas and oil properties with no gain or loss recognized, and our proved reserves were reduced accordingly. We have also committed to purchase natural gas and liquids associated with our VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices.
	As of September 30, 2014, our outstanding VPPs consisted of the following:
									Volume Sold
	VPP #		Date of VPP	Location		Proceeds			Natural Gas		Oil		NGL		Total
						($ in millions)			(bcf)		(mmbbl)		(mmbbl)		(bcfe)
	10		Mar-12	Anadarko Basin Granite		$	744		87		3		9.2		160
				Wash
	9		May-11	Mid-Continent		853			138		1.7		4.8		177
	8		September 2010	Barnett Shale		1,150			390		—		—		390
	6		February 2010	East Texas and NW		180			44		0.3		—		46
				Louisiana
	4		December 2008	Anadarko and Arkoma		412			95		0.5		—		98
				Basins
	3		Aug-08	Anadarko Basin		600			93		—		—		93
	2		May-08	Texas, Oklahoma and		622			94		—		—		94
				Kansas
	1		December 2007	Kentucky and West		1,100			208		—		—		208
				Virginia
						$	5,661		1,149		5.5		14		1,266
	The volumes produced on behalf of our VPP buyers for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:
			Three Months Ended September 30, 2014									Three Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL		Total		Natural Gas		Oil		NGL	Total
			(bcf)		(mbbl)			(mbbl)		(bcfe)		(bcf)		(mbbl)		(mbbl)	(bcfe)
	10		2.6		98			314.5		5		3.3		131		371.9	6.3
	9		3.8		46.1			101.5		4.7		4.2		52.3		112.2	5.2
	8		14.8		—			—		14.8		16.7		—		—	16.7
	6		1.1		6			—		1.1		1.2		6		—	1.2
	5(a)		1.2		4.2			—		1.2		1.9		6.7		—	1.9
	4		2.2		11.9			—		2.3		2.5		13.5		—	2.6
	3		1.8		—			—		1.8		2		—		—	2
	2		1.1		—			—		1.1		2.5		—		—	2.5
	1		3.4		—			—		3.4		3.5		—		—	3.5
			32		166.2			416		35.4		37.8		209.5		484.1	41.9
	__________________________________________
	(a)	In the Current Quarter, we divested the properties associated with VPP #5.
			Nine Months Ended September 30, 2014									Nine Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL		Total		Natural Gas		Oil		NGL	Total
			(bcf)		(mbbl)			(mbbl)		(bcfe)		(bcf)		(mbbl)		(mbbl)	(bcfe)
	10		8.1		310			989.6		15.8		10.3		426		1,158.60	19.8
	9		11.7		142.6			311.9		14.4		12.9		162.7		346.4	16
	8		45.7		—			—		45.7		52		—		—	52
	6		3.3		18			—		3.4		3.6		18		—	3.6
	5(a)		4.6		16.5			—		4.7		5.8		18.9		—	5.8
	4		6.8		36.5			—		7		7.7		41.5		—	8
	3		5.5		—			—		5.5		6.1		—		—	6.1
	2		5.1		—			—		5.1		7.8		—		—	7.8
	1		10.4		—			—		10.4		10.9		—		—	10.9
			101.2		523.6			1,301.50		112		117.1		667.1		1,505.00	130
__________________________________________
(a)	In the Current Quarter, we divested the properties associated with VPP #5.
The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2014 were as follows:
			Volume Remaining as of September 30, 2014
VPP #		Term Remaining	Natural Gas			Oil		NGL		Total
		(in months)	(bcf)			(mmbbl)		(mmbbl)		(bcfe)
10		89	40.5			1.4		5		78.9
9		77	77			0.9		2		94.5
8		11	50.9			—		—		50.9
6		64	18.1			0.1		—		18.9
4		27	17.5			0.1		—		18.1
3		58	25.6			—		—		25.6
2		55	14.9			—		—		14.9
1		99	94.9			—		—		94.9
			339.4			2.5		7		396.7

Investments_Note

Investments (Note)	9 Months Ended
	Sep. 30, 2014
Investments [Abstract]	'
Investments Disclosure [Text Block]	'
	Investments
	A summary of our investments, including our approximate ownership percentage and carrying value as of September 30, 2014 and December 31, 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	September 30,	December 31,	September 30,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	110	$	138
	Sundrop Fuels, Inc.	Equity	56%	56%	132		135
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Other	—	—%	—%	12		61
	Total investments				$	254	$	477
	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 $37 million for our share of FTS’s net loss and recorded an accretion adjustment of $9 million related to the excess of our underlying equity in net assets of FTS over our carrying value.
	As of September 30, 2014, the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $45 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. In the Current Period, we recorded a $17 million charge related to our share of Sundrop's net loss and $14 million of capitalized interest associated with the construction of Sundrop’s plant. The capitalized interest is added to the investment carrying value in excess of our underlying equity and will be amortized over the life of the plant, once it is placed into service. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $76 million.
	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 Current 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.
	Clean Energy Fuels Corp. In the Prior Period, we sold our $100 million investment in convertible notes of Clean Energy Fuels Corp. (Clean Energy) for cash proceeds of $85 million. The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale.
	Other. In the Current 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.
	In the Prior Period, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

Variable_Interest_Entities_Not

Variable Interest Entities (Note)	9 Months Ended
	Sep. 30, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]	'
Variable Interest Entities Disclosure [Text Block]	'
	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 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 7. 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 September 30, 2014, $1 million of cash and cash equivalents, $488 million of proved natural gas and oil properties, $220 million of accumulated depreciation, depletion and amortization and $16 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 $9 million as of September 30, 2014.

Other_Property_and_Equipment_N

Other Property and Equipment (Note)	9 Months Ended
	Sep. 30, 2014
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]	'
Other Property and Equipment Disclosure [Text Block]	'
	Other Property and Equipment
	Net Gains on Sales of Fixed Assets
	A summary by asset class of (gains) or losses on sales of fixed assets for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2014			2013			2014			2013
		($ in millions)
	Natural gas compressors	$	(75	)	$	—		$	(195	)	$	—
	Gathering systems and treating plants	(5		)	(132		)	8			(311		)
	Oilfield services equipment	—			—			(7		)	1
	Buildings and land	(6		)	1			(5		)	24
	Other	—			(1		)	(2		)	(4		)
	Total net gains on sales of fixed assets	$	(86	)	$	(132	)	$	(201	)	$	(290	)
	Natural Gas Compressors. In the Current Quarter, as part of a divestiture of noncore natural gas and oil properties in South Texas, we sold 61 compressors and related equipment to Hilcorp Energy Company for $19 million. We recorded a $6 million gain associated with the compressors sold. In the Current Period, we sold 499 compressors and related equipment to Exterran Partners, L.P. for approximately $495 million, which included the sale of 162 compressors and related equipment for approximately $133 million in the Current Quarter. We recorded a $161 million gain associated with the transactions, which included a $68 million gain in the Current Quarter. In the Current Period, we also sold 102 compressors and related equipment to Access Midstream Partners, L.P. for proceeds of approximately $159 million. We recorded a $24 million gain associated with the transaction.
	Gathering Systems and Treating Plants. In the Prior Quarter, we sold our wholly owned midstream subsidiary Mid-America Midstream Gas Services, L.L.C. (MAMGS) to SemGas, L.P., a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million. We recorded a $141 million gain associated with the transaction. In the Prior Period, we sold our wholly owned subsidiary Granite Wash Midstream Gas Services, L.L.C. (GWMGS) to MarkWest Oklahoma Gas Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners, L.P. (MWE), for net proceeds of approximately $252 million. We recorded a $105 million gain associated with this transaction. The transaction with MWE included long-term fixed fee arrangements for gas gathering, compression, treating and processing services in the Anadarko Basin. In the Prior Period, we also sold our interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP for proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction.
	Oilfield Services Equipment. In the Current Period, we sold substantially all of our crude oil hauling assets for approximately $44 million. We recorded a $23 million gain associated with the transaction. Also, in the Current Period, we sold 14 rigs for approximately $14 million and recorded a $14 million loss.
	Buildings and Land. In the Current Quarter and the Current Period, the net gains on sales of buildings and land were mainly from the sale of certain buildings and land located primarily in our Barnett Shale operating area. In the Prior Period, the net losses on sales of buildings and land were mainly from the sale of certain of our buildings and land located primarily in our Barnett Shale operating area.
	Assets Held for Sale
	In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of September 30, 2014, we were continuing to pursue the sale of land located in the Fort Worth, Texas area. Land and buildings are recorded under our other segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets are reflected as held for sale as of September 30, 2014. Natural gas and oil properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets held for sale on our condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 is detailed below.
		September 30,			December 31,
		2014			2013
		($ in millions)
	Buildings and land, net of accumulated depreciation	$	101		$	405
	Compressors, net of accumulated depreciation	—			285
	Oilfield services equipment, net of accumulated depreciation	—			29
	Gathering systems and treating plants, net of accumulated depreciation	—			11
	Property and equipment held for sale, net	$	101		$	730
	In March 2014, management determined that certain properties in the Fort Worth area of the Barnett Shale, previously classified as held for sale as of December 31, 2013, would be reclassified as held for use. As of December 31, 2013, management’s development plan for the Barnett Shale did not contemplate the need for the underlying properties (for pad drilling in certain urban locations around Fort Worth) and the properties were marketed for sale. Management modified its development plan and consequently these properties no longer met the criteria to be classified as held for sale as of March 31, 2014. The properties were measured at the lesser of their fair value at the date of the decision not to sell or their carrying amount before being classified as held for sale. During the 2014 first quarter, we reclassified $116 million of such properties to held for use classification. There was no impact to the statement of operations related to this reclassification.

Impairments_of_Fixed_Assets_an

Impairments of Fixed Assets and Other (Note)	9 Months Ended
	Sep. 30, 2014
Asset Impairment Charges [Abstract]	'
Asset Impairment Charges [Text Block]	'
	Impairments of Fixed Assets and Other
	We review our long-lived assets, other than our natural gas and oil properties which are subject to quarterly full cost ceiling tests, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable and recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2014		2013		2014		2013
		($ in millions)
	Natural gas compressors	$	11	$	—	$	11	$	—
	Gathering systems and treating plants	—		21		10		22
	Oilfield services equipment	—		24		23		27
	Buildings and land	4		8		9		247
	Other	—		32		22		47
	Total impairments of fixed assets and other	$	15	$	85	$	75	$	343
	Natural Gas Compressors. In the Current Quarter, we recognized an impairment loss of $11 million related to certain of our compressors. The compressors are included in our marketing, gathering and compression operating segment.
	Gathering Systems and Treating Plants. In the Current Period, we recognized an impairment loss of $10 million related to certain gathering systems and treating plants. In the Prior Quarter, we recognized approximately $18 million of impairment losses on certain of our gathering systems. The gathering systems and treating plants are included in our marketing, gathering and compression operating segment.
	Oilfield Services Equipment. In the Current 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. We recognized an impairment loss of approximately $15 million of leasehold improvements associated with these transactions. In the Prior Quarter, we recognized an impairment loss of $24 million on eight owned drilling rigs. The drilling rigs and equipment were included in our former oilfield services operating segment.
	Buildings and Land. In the Prior Period, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. We recognized an impairment loss of $166 million during the Prior Period on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. Given the impairment losses associated with these assets, we tested other noncore buildings and land that we own in the Oklahoma City area for recoverability. As a result of this test, we recognized an impairment loss of $44 million on these assets in the Prior Period. Due to a decrease in the estimated market prices of certain property classified as held for sale in the Fort Worth area, we recognized an additional impairment loss of $31 million in the Prior Period. The impaired buildings and land are included in our other segment.
	Other. Under the terms of our joint venture agreements (see Note 10), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. In the Current Period, we revised our estimate of our net acreage shortfall as of December 31, 2012 under the terms of our Barnett Shale joint venture agreement with Total and recorded an additional $22 million charge. See Note 5 for additional discussion regarding our net acreage maintenance commitments. In the Prior Quarter, we terminated a gas gathering agreement and recorded a charge of $26 million within impairment of fixed assets and other in the condensed consolidated statement of operations.
	Nonrecurring Fair Value Measurements. Fair value measurements for 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, the values were classified as Level 2 in the fair value hierarchy. Fair value measurements of the buildings and land discussed above were based on prices from orderly sales transactions for comparable properties between market participants, purchase offers we received from third parties and, in certain cases, discounted cash flows. As some inputs used were not observable in the market, these values were classified as Level 3 in the fair value hierarchy.

Restructuring_and_Other_Termin

Restructuring and Other Termination Benefits (Note)	9 Months Ended
	Sep. 30, 2014
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Activities Disclosure [Text Block]	'
	Restructuring and Other Termination Costs
	On June 30, 2014, we completed the spin-off of our oilfield services business through a pro rata distribution of SSE common stock to holders of Chesapeake common stock. In connection with the spin-off, during the Current Period, we incurred restructuring charges of $15 million consisting of transaction costs, stock-based compensation adjustments and debt extinguishment costs. See Note 2 for further discussion of the spin-off.
	On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all such notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we recorded $31 million of termination charges for employees terminated in September 2013 and recorded the remaining $35 million in the 2013 fourth quarter for employees terminated in October 2013. Of the $31 million in charges incurred in the Prior Quarter, $1 million was paid in the Prior Quarter.
	On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells and acreage. In the Prior Period, we incurred charges of approximately $67 million related to Mr. McClendon’s departure.
	In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period, which resulted in $63 million of expense for the Prior Period.
	During the Prior Quarter and the Prior Period, we also incurred charges of approximately $28 million and $42 million related to other workforce reductions, including separations of executive officers other than the former CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment.
	Below is a summary of our restructuring and other termination costs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended					Nine Months Ended
			September 30,					September 30,
			2014			2013		2014			2013
			($ in millions)
	Oilfield services spin-off costs:
	Transaction costs		$	3		$	—	$	17		$	—
	Stock-based compensation adjustments for		—			—		5			—
	Chesapeake employees
	Stock-based compensation forfeitures for SSE		—			—		(10		)	—
	employees
	Debt extinguishment costs		—			—		3			—
	Total oilfield services spin-off costs		3			—		15			—
	Restructuring charges under workforce reduction plan:
	Salary expense		—			5		—			5
	Acceleration of stock-based compensation		—			25		—			25
	Other termination benefits		—			1		—			1
	Total restructuring changes under workforce		—			31		—			31
	reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense		—			—		—			11
	Acceleration of 2008 performance bonus clawback		—			—		—			11
	Acceleration of stock-based compensation		—			—		—			22
	Acceleration of performance share unit awards(a)		(7		)	3		(5		)	16
	Estimated aircraft usage benefits		—			—		—			7
	Total termination benefits provided to		(7		)	3		(5		)	67
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			—		—			32
	Acceleration of stock-based compensation		—			1		—			28
	Other termination benefits		—			—		—			3
	Total termination benefits provided to VSP		—			1		—			63
	participants
	Other termination benefits(a)		(10		)	28		2			42
	Total restructuring and other termination costs		$	(14	)	$	63	$	12		$	203
	____________________________________________
	(a)	The Current Quarter and Current Period amounts are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 8.

Fair_Value_Measurements_Note

Fair Value Measurements (Note)	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements Disclosure [Text Block]	'
	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 September 30, 2014 and December 31, 2013:
		Quoted			Significant		Significant		Total
		Prices in			Other		Unobservable		Fair Value
		Active			Observable		Inputs
		Markets			Inputs		(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of September 30, 2014
	Financial Assets (Liabilities):
	Other current assets	$	57		$	—	$	—	$	57
	Other current liabilities	(58		)	—		—		(58		)
	Total	$	(1	)	$	—	$	—	$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—	$	—	$	80
	Other current liabilities	(82		)	—		—		(82		)
	Total	$	(2	)	$	—	$	—	$	(2	)
	See Note 4 for information regarding fair value of other financial instruments. See Note 9 for information regarding fair value measurement of derivatives.
	Nonrecurring Fair Value Measurements
	See Note 14 regarding nonrecurring fair value measurements.

Segment_Information_Note

Segment Information (Note)	9 Months Ended
	Sep. 30, 2014
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]	'
Segment Information Disclosure [Text Block]	'
	Segment Information
	As of September 30, 2014, 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 natural gas, oil and NGL. The marketing, gathering and compression operating segment is responsible for marketing, gathering and compression of natural gas, oil and NGL. In addition, prior to the spin-off described in Note 2, 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 natural gas, oil 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. Such amounts totaled $2.150 billion, $2.002 billion, $6.746 billion and $5.682 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 $0, $306 million, $544 million and $1.041 billion the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively. No income was recognized in our condensed consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells.
	The following table presents selected financial information for Chesapeake’s operating segments:
		Exploration		Marketing,			Former			Other			Intercompany			Consolidated
		and		Gathering			Oilfield						Eliminations			Total
		Production		and			Services
				Compression
		($ in millions)
	Three Months Ended
	September 30, 2014:
	Revenues	$	2,341	$	5,512		$	—		$	—		$	(2,150	)	$	5,703
	Intersegment revenues	—		(2,150		)	—			—			2,150			—
	Total revenues	$	2,341	$	3,362		$	—		$	—		$	—		$	5,703
	Income (Loss) Before	$	987	$	113		$	—		$	(63	)	$	92		$	1,129
	Income Taxes
	Three Months Ended
	September 30, 2013:
	Revenues	$	1,586	$	5,034		$	551		$	4		$	(2,308	)	$	4,867
	Intersegment revenues	—		(2,002		)	(306		)	—			2,308			—
	Total revenues	$	1,586	$	3,032		$	245		$	4		$	—		$	4,867
	Income (Loss) Before	$	430	$	128		$	(37	)	$	(48	)	$	(86	)	$	387
	Income Taxes
	Nine Months Ended
	September 30, 2014:
	Revenues	$	5,812	$	16,289		$	1,060		$	30		$	(7,290	)	$	15,901
	Intersegment revenues	—		(6,746		)	(544		)	—			7,290			—
	Total revenues	$	5,812	$	9,543		$	516		$	30		$	—		$	15,901
	Income (Loss) Before	$	2,089	$	325		$	(16	)	$	(24	)	$	(128	)	$	2,246
	Income Taxes
	Nine Months Ended
	September 30, 2013:
	Revenues	$	5,444	$	12,553		$	1,677		$	27		$	(6,736	)	$	12,965
	Intersegment revenues	—		(5,682		)	(1,041		)	(13		)	6,736			—
	Total revenues	$	5,444	$	6,871		$	636		$	14		$	—		$	12,965
	Income (Loss) Before	$	654	$	395		$	(12	)	$	808		$	(284	)	$	1,561
	Income Taxes
	As of
	September 30, 2014:
	Total Assets	$	34,876	$	2,420		$	—		$	4,357		$	(1,135	)	$	40,518
	As of
	December 31, 2013:
	Total Assets	$	35,341	$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information (Note)	9 Months Ended
	Sep. 30, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	'
	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 4 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.
	Set forth below are condensed consolidating financial statements for Chesapeake Energy Corporation (parent) on a stand-alone, unconsolidated basis, and its combined guarantor and combined non-guarantor subsidiaries as of September 30, 2014 and December 31, 2013 and for the three and nine months ended September 30, 2014 and 2013. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF SEPTEMBER 30, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	13		$	—		$	90		$	(13	)	$	90
	Restricted cash		—			—			38			—			38
	Other		73			2,737			191			—			3,001
	Intercompany receivable, net		24,366			—			—			(24,366		)	—
	Total Current Assets		24,452			2,737			319			(24,379		)	3,129
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			30,739			2,999			499			34,237
	Other property and equipment, net		—			2,309			5			—			2,314
	Property and equipment held for		—			101			—			—			101
	sale, net
	Total Property and Equipment,		—			33,149			3,004			499			36,652
	Net
	LONG-TERM ASSETS:
	Other assets		105			604			28			—			737
	Investments in subsidiaries and		3,805			686			—			(4,491		)	—
	intercompany advances
	TOTAL ASSETS		$	28,362		$	37,176		$	3,351		$	(28,371	)	$	40,518
	CURRENT LIABILITIES:
	Current liabilities		$	247		$	5,308		$	68		$	(21	)	$	5,602
	Intercompany payable, net		—			23,807			703			(24,510		)	—
	Total Current Liabilities		247			29,115			771			(24,531		)	5,602
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,533			59			—			—			11,592
	Deferred income tax liabilities		132			3,305			713			135			4,285
	Other long-term liabilities		130			892			386			—			1,408
	Total Long-Term Liabilities		11,795			4,256			1,099			135			17,285
	EQUITY:
	Chesapeake stockholders’ equity		16,320			3,805			1,481			(5,286		)	16,320
	Noncontrolling interests		—			—			—			1,311			1,311
	Total Equity		16,320			3,805			1,481			(3,975		)	17,631
	TOTAL LIABILITIES AND EQUITY		$	28,362		$	37,176		$	3,351		$	(28,371	)	$	40,518
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	799		$	—		$	39		$	(1	)	$	837
	Restricted cash		—			—			82			(7		)	75
	Other		103			2,411			578			(348		)	2,744
	Intercompany receivable, net		25,357			—			—			(25,357		)	—
	Total Current Assets		26,259			2,411			699			(25,713		)	3,656
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,295			3,113			185			32,593
	Other property and equipment, net		—			2,360			1,452			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			32,356			4,594			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,161			96			(376		)	992
	Investments in subsidiaries and		2,361			(262		)	—			(2,099		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,666		$	5,389		$	(28,004	)	$	41,782
CURRENT LIABILITIES:
Current liabilities		$	300		$	5,227		$	344		$	(356	)	$	5,515
Intercompany payable, net		—			24,775			558			(25,333		)	—
Total Current Liabilities		300			30,002			902			(25,689		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,281			830			87			3,407
Other long-term liabilities		396			1,022			788			(372		)	1,834
Total Long-Term Liabilities		12,436			3,303			2,673			(285		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,361			1,814			(4,175		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,361			1,814			(2,030		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,666		$	5,389		$	(28,004	)	$	41,782
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	2,085		$	256		$	—		$	2,341
Marketing, gathering and compression		—			3,361			1			—			3,362
Oilfield services		—			—			—			—			—
Total Revenues		—			5,446			257			—			5,703
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			284			14			—			298
Production taxes		—			59			3			—			62
Marketing, gathering and compression		—			3,368			1			—			3,369
Oilfield services		—			—			—			—			—
General and administrative		—			57			3			—			60
Restructuring and other termination costs		—			(14		)	—			—			(14		)
Provision for legal contingencies		—			100			—			—			100
Natural gas, oil and NGL depreciation,		—			599			82			7			688
depletion and amortization
Depreciation and amortization of other		—			37			—			—			37
assets
Impairment of natural gas and oil properties		—			—			104			(104		)	—
Impairments of fixed assets and other		—			15			—			—			15
Net gains on sales of fixed assets		—			(86		)	—			—			(86		)
Total Operating Expenses		—			4,419			207			(97		)	4,529
INCOME FROM OPERATIONS		—			1,027			50			97			1,174
OTHER INCOME (EXPENSE):
Interest expense		(178		)	(11		)	—			172			(17		)
Losses on investments		—			(27		)	—			—			(27		)
Other income (expense)		56			120			(4		)	(173		)	(1		)
Equity in net earnings of subsidiary		737			(2		)	—			(735		)	—
Total Other Income (Expense)		615			80			(4		)	(736		)	(45		)
INCOME BEFORE INCOME TAXES		615			1,107			46			(639		)	1,129
INCOME TAX EXPENSE (BENEFIT)		(47		)	429			18			37			437
NET INCOME		662			678			28			(676		)	692
Net income attributable to		—			—			—			(30		)	(30		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		662			678			28			(706		)	662
TO CHESAPEAKE
Other comprehensive income		—			3			—			—			3
COMPREHENSIVE INCOME		$	662		$	681		$	28		$	(706	)	$	665
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	1,340		$	245		$	1		$	1,586
Marketing, gathering and compression		—			3,031			1			—			3,032
Oilfield services		—			57			464			(272		)	249
Total Revenues		—			4,428			710			(271		)	4,867
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			262			20			—			282
Production taxes		—			60			2			—			62
Marketing, gathering and compression		—			3,009			—			—			3,009
Oilfield services		—			70			385			(244		)	211
General and administrative		—			97			24			(1		)	120
Restructuring and other termination costs		—			63			—			—			63
Natural gas, oil and NGL depreciation,		—			549			103			—			652
depletion and amortization
Depreciation and amortization of other		—			45			71			(37		)	79
assets
Impairment of natural gas and oil		—			—			99			(99		)	—
properties
Impairments of fixed assets and other		—			31			54			—			85
Net gains on sales of fixed assets		—			(133		)	—			1			(132		)
Total Operating Expenses		—			4,053			758			(380		)	4,431
INCOME FROM OPERATIONS		—			375			(48		)	109			436
OTHER INCOME (EXPENSE):
Interest expense		(207		)	(27		)	(21		)	215			(40		)
Losses on investments		—			(22		)	—			—			(22		)
Net gain on sales of investments		—			3			—			—			3
Other income		208			44			2			(244		)	10
Equity in net earnings (losses) of		201			(87		)	—			(114		)	—
subsidiary
Total Other Income (Expense)		202			(89		)	(19		)	(143		)	(49		)
INCOME BEFORE INCOME TAXES		202			286			(67		)	(34		)	387
INCOME TAX EXPENSE (BENEFIT)		—			142			(25		)	30			147
NET INCOME (LOSS)		202			144			(42		)	(64		)	240
Net income attributable to		—			—			—			(38		)	(38		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		202			144			(42		)	(102		)	202
TO CHESAPEAKE (LOSS)
Other comprehensive income (loss)		2			1			(2		)	—			1
COMPREHENSIVE INCOME		$	204		$	145		$	(44	)	$	(102	)	$	203
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	5,100		$	715		$	(3	)	$	5,812
Marketing, gathering and compression		—			9,539			4			—			9,543
Oilfield services		—			40			984			(478		)	546
Total Revenues		—			14,679			1,703			(481		)	15,901
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			818			50			—			868
Production taxes		—			177			8			—			185
Marketing, gathering and compression		—			9,512			3			—			9,515
Oilfield services		—			54			769			(392		)	431
General and administrative		—			176			53			—			229
Restructuring and other termination costs		—			9			3			—			12
Provision for legal contingencies		—			100			—			—			100
Natural gas, oil and NGL depreciation,		—			1,750			211			16			1,977
depletion and amortization
Depreciation and amortization of other		—			116			142			(64		)	194
assets
Impairment of natural gas and oil properties		—			—			202			(202		)	—
Impairments of fixed assets and other		—			52			23			—			75
Net gains on sales of fixed assets		—			(194		)	(7		)	—			(201		)
Total Operating Expenses		—			12,570			1,457			(642		)	13,385
INCOME FROM OPERATIONS		—			2,109			246			161			2,516
OTHER INCOME (EXPENSE):
Interest expense		(524		)	(14		)	(42		)	498			(82		)
Losses on investments		—			(69		)	(5		)	2			(72		)
Net gain on sales of investments		—			67			—			—			67
Losses on purchases of debt		(195		)	—			—			—			(195		)
Other income (loss)		535			12			(2		)	(533		)	12
Equity in net earnings of subsidiary		1,391			11			—			(1,402		)	—
Total Other Income (Expense)		1,207			7			(49		)	(1,435		)	(270		)
INCOME BEFORE INCOME TAXES		1,207			2,116			197			(1,274		)	2,246
INCOME TAX EXPENSE (BENEFIT)		(70		)	804			76			49			859
NET INCOME		1,277			1,312			121			(1,323		)	1,387
Net income attributable to		—			—			—			(110		)	(110		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		1,277			1,312			121			(1,433		)	1,277
TO CHESAPEAKE
Other comprehensive income		3			8			—			—			11
COMPREHENSIVE INCOME		$	1,280		$	1,320		$	121		$	(1,433	)	$	1,288
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,903		$	532		$	9		$	5,444
Marketing, gathering and compression		—			6,861			10			—			6,871
Oilfield services		—			172			1,398			(920		)	650
Total Revenues		—			11,936			1,940			(911		)	12,965
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			833			44			—			877
Production taxes		—			167			6			—			173
Marketing, gathering and compression		—			6,776			5			—			6,781
Oilfield services		—			216			1,101			(774		)	543
General and administrative		—			267			69			—			336
Restructuring and other termination costs		—			200			3			—			203
Natural gas, oil and NGL depreciation,		—			1,729			216			—			1,945
depletion and amortization
Depreciation and amortization of other		—			142			210			(118		)	234
assets
Impairment of natural gas and oil		—			—			260			(260		)	—
properties
Impairments of fixed assets and other		—			282			61			—			343
Net gains on sales of fixed assets		—			(291		)	—			1			(290		)
Total Operating Expenses		—			10,321			1,975			(1,151		)	11,145
INCOME (LOSS) FROM OPERATIONS		—			1,615			(35		)	240			1,820
OTHER INCOME (EXPENSE):
Interest expense		(703		)	(70		)	(63		)	672			(164		)
Losses on investments		—			(36		)	—			—			(36		)
Net gain on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	—			—			—			(70		)
Other income		651			120			7			(760		)	18
Equity in net earnings (losses) of		916			(241		)	—			(675		)	—
subsidiary
Total Other Income (Expense)		794			(234		)	(56		)	(763		)	(259		)
INCOME (LOSS) BEFORE INCOME TAXES		794			1,381			(91		)	(523		)	1,561
INCOME TAX EXPENSE (BENEFIT)		(46		)	617			(35		)	58			594
NET INCOME (LOSS)		840			764			(56		)	(581		)	967
Net income attributable to		—			—			—			(127		)	(127		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		840			764			(56		)	(708		)	840
TO CHESAPEAKE
Other comprehensive income (loss)		2			12			(1		)	—			13
COMPREHENSIVE INCOME		$	842		$	776		$	(57	)	$	(708	)	$	853
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	3,188		$	617		$	—		$	3,805
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(2,847		)	(338		)	—			(3,185		)
Acquisitions of proved and unproved properties		—			(1,020		)	(3		)	—			(1,023		)
Proceeds from divestitures of proved and unproved properties		—			726			(3		)	—			723
Additions to other property and equipment		—			(423		)	(252		)	—			(675		)
Other investing activities		—			1,143			60			19			1,222
Net Cash Used In Investing		—			(2,421		)	(536		)	19			(2,938		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			2,856			717			—			3,573
Payments on credit facilities borrowings		—			(2,797		)	(1,099		)	—			(3,896		)
Proceeds from issuance of senior notes, net of discount and offering costs		2,966			—			494			—			3,460
Proceeds from issuance of oilfield services term loan, net of issuance costs		—			—			394			—			394
Cash paid to purchase debt		(3,362		)	—			—			—			(3,362		)
Other financing activities		(293		)	(1,300		)	(159		)	(31		)	(1,783		)
Intercompany advances, net		(97		)	474			(377		)	—			—
Net Cash Provided By (Used In)		(786		)	(767		)	(30		)	(31		)	(1,614		)
Financing Activities
Net increase (decrease) in cash and cash		(786		)	—			51			(12		)	(747		)
equivalents
Cash and cash equivalents, beginning of		799			—			39			(1		)	837
period
Cash and cash equivalents, end of period		$	13		$	—		$	90		$	(13	)	$	90
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	3,321		$	298		$	(33	)	$	3,586
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Drilling and completion costs		—			(3,826		)	(644		)	—			(4,470		)
Acquisitions of proved and unproved properties		—			(402		)	(409		)	—			(811		)
Proceeds from divestitures of proved and unproved properties		—			2,736			53			—			2,789
Additions to other property and equipment		—			(418		)	(221		)	—			(639		)
Other investing activities		—			67			757			260			1,084
Net Cash Used In Investing		—			(1,843		)	(464		)	260			(2,047		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities borrowings		—			6,311			825			—			7,136
Payments on credit facilities borrowings		—			(6,310		)	(958		)	—			(7,268		)
Proceeds from issuance of senior notes, net of discount and offering costs		2,274			—			—			—			2,274
Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
Proceeds from sales of noncontrolling interests		—			5			—			—			5
Other financing activities		(374		)	(297		)	46			(220		)	(845		)
Intercompany advances, net		979			(1,187		)	208			—			—
Net Cash Provided By (Used		738			(1,478		)	121			(220		)	(839		)
In) Financing Activities
Net increase (decrease) in cash and cash		738			—			(45		)	7			700
equivalents
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	966		$	—		$	14		$	7		$	987
___________________________________________
(a)	We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012 and September 30, 2013, $228 million and $966 million, respectively, were incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards (Note)	9 Months Ended
	Sep. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	'
	Recently Issued Accounting Standards
	In February 2013, the Financial Accounting Standards Board (FASB) issued guidance on the recognition, measurement and disclosure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. We adopted this standard January 1, 2014, and it did not have a material impact on our consolidated financial statements.
	In April 2014, the FASB issued an accounting standards update that raises the threshold for a disposal or classification as held for sale to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. This accounting standards update is effective for us beginning on January 1, 2015, and it is not expected to have a material impact on our consolidated financial statements.
	In May 2014, the FASB issued updated revenue recognition guidance to clarify the principles for recognizing revenue and to develop a common revenue standard for U.S. GAAP and international financial reporting standards. The new standard requires the recognition of revenue to depict the transfer of promised goods to customers in an amount reflecting the consideration the company expects to receive in the exchange. The accounting standards update is effective for us beginning January 1, 2017, including retrospective application to comparative periods, and we are evaluating the impact on our consolidated financial statements.

Subsequent_Events_Note

Subsequent Events (Note)	9 Months Ended
	Sep. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events Disclosure [Text Block]	'
	Subsequent Events
	On October 14, 2014, we entered into a purchase and sale agreement to sell certain assets in the southern Marcellus Shale and a portion of the eastern Utica Shale to a subsidiary of Southwestern Energy Company (Southwestern) for aggregate proceeds of approximately $5.375 billion, subject to customary closing and post-closing adjustments. We estimate the after-tax proceeds will not differ materially from the aggregate proceeds due to the utilization of other current period tax losses, net operating loss carry forwards or like-kind exchange strategies. Upon execution of the purchase and sale agreement, Southwestern paid us a $269 million deposit toward the purchase price. We agreed to sell approximately 413,000 net acres and approximately 1,500 wells in northern West Virginia and southern Pennsylvania, of which 435 wells are in the Marcellus or Utica formations, along with related gathering assets and property, plant and equipment. Average net daily production from these properties was approximately 56,000 boe during September 2014, consisting of 184,000 mcf of natural gas, 20,000 barrels of NGL and 5,000 barrels of condensate. As of December 31, 2013, net proved reserves associated with these properties were approximately 221 mmboe, or 8% of total proved reserves. The transaction, which is subject to certain customary closing conditions, including the receipt of third-party consents and waiver of participation rights, is expected to close in the fourth quarter of 2014.
	Under full cost accounting rules, we do not anticipate the recognition of a gain or loss on this transaction as the sale will not involve a significant change in proved reserves and will not significantly alter the relationship between costs and proved reserves.

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2014
Accounting Policies [Abstract]	'
Basis of Accounting, Policy [Policy Text Block]	'
	Basis of Presentation
	The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation (Chesapeake or the Company) and its subsidiaries were prepared in accordance with accounting principles generally accepted in the United States (U.S. GAAP) and include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake has a controlling financial interest. Intercompany accounts and balances have been eliminated. These financial statements were prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with U.S. GAAP.
	This Form 10-Q relates to the three and nine months ended September 30, 2014 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2013 (the “Prior Quarter” and the “Prior Period”, respectively). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2013 (“2013 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 presentation of the results for the interim periods have been reflected. The results for the Current Quarter and the Current Period are not necessarily indicative of the results to be expected for the full year.

Variable_Interest_Entities_Pol

Variable Interest Entities (Policies)	9 Months Ended
	Sep. 30, 2014
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]	'
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	'
	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 qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.

Impairments_of_Fixed_Assets_an1

Impairments of Fixed Assets and Other (Policies)	9 Months Ended
	Sep. 30, 2014
Asset Impairment Charges [Abstract]	'
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	'
	We review our long-lived assets, other than our natural gas and oil properties which are subject to quarterly full cost ceiling tests, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable and recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]	'
	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 such shares, were excluded from the calculation of diluted EPS as the effect was antidilutive. The impact of our stock options was immaterial in the calculation of diluted EPS for these periods.
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended September 30, 2014:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	59
	5.75% cumulative convertible preferred stock (series A)	$	16	42
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	6
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	3
	Three Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	2
	Nine Months Ended September 30, 2014:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	59
	5.75% cumulative convertible preferred stock (series A)	$	47	42
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	6
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3
	Nine Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3

Debt_Tables

Debt (Tables)	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Schedule of Debt [Table Text Block]	'
	Our long-term debt consisted of the following as of September 30, 2014 and December 31, 2013:
			September 30,				December 31,
			2014				2013
			($ in millions)
	Term loan due 2017(a)		$	—			$	2,000
	9.5% senior notes due 2015(b)		—				1,265
	3.25% senior notes due 2016		500				500
	6.25% euro-denominated senior notes due 2017(c)		435				473
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018(d)		—				97
	7.25% senior notes due 2018		669				669
	Floating rate senior notes due 2019		1,500				—
	6.625% senior notes due 2019(e)		—				650
	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				—
	5.75% senior notes due 2023		1,100				1,100
	2.75% contingent convertible senior notes due 2035(f)		396				396
	2.5% contingent convertible senior notes due 2037(f)		1,168				1,168
	2.25% contingent convertible senior notes due 2038(f)		347				347
	Corporate revolving bank credit facility		59				—
	Oilfield services revolving bank credit facility(g)		—				405
	Discount on senior notes and term loan(h)		(252		)		(357		)
	Interest rate derivatives(i)		10				13
	Total long-term debt, net		$	11,592			$	12,886
	___________________________________________
	(a)	In the Current Period, we repaid the borrowings outstanding under the term loan due 2017 with a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes issued in the Current Period.
	(b)	In the Current Period, we completed a tender offer for and redemption of the 9.5% Senior Notes due 2015.
	(c)	The principal amount shown is based on the exchange rate of $1.2631 to €1.00 and $1.3743 to €1.00 as of September 30, 2014 and December 31, 2013, respectively. See Note 9 for information on our related foreign currency derivatives.
	(d)	In the Current Period, we redeemed all outstanding 6.875% Senior Notes due 2018.
	(e)	Initial issuers were COO and Chesapeake Oilfield Finance, Inc., a wholly owned subsidiary of COO. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes. In the Current Period, in connection with the spin-off of our oilfield services business, the obligations with respect to the COO senior notes were removed from our condensed consolidated balance sheet. See Note 2 for further discussion of the spin-off.
	(f)	The repurchase, conversion, contingent interest and redemption provisions of our contingent convertible senior notes are as follows:
	Holders’ Demand Repurchase Rights. The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date.
	Optional Conversion by Holders. At the holder’s option, prior to maturity under certain circumstances, the notes are convertible into cash and, if applicable, shares of our common stock using a net share settlement process. One such triggering circumstance is when the price of our common stock exceeds a threshold amount during a specified period in a fiscal quarter. Convertibility based on common stock price is measured quarterly. During the specified period in the third quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes and, as a result, the holders do not have the option to convert their notes into cash and common stock in the fourth quarter of 2014 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 in 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 such 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 the dividend of SSE common stock paid in the spin-off of our oilfield services business and 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		Holders' Demand		Common Stock				Contingent Interest
	Convertible		Repurchase Dates		Price Conversion				First Payable
	Senior  Notes				Thresholds				(if applicable)
	2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	45.22			May 14, 2016
	2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	59.71			November 14, 2017
	2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	100.45			June 14, 2019
	Optional Redemption by the Company. We may redeem the 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.
	(g)	In the Current Period, in connection with the spin-off of our oilfield services business, we terminated our oilfield services credit facility. See Note 2 for further discussion of the spin-off.
	(h)	Discount as of September 30, 2014 and December 31, 2013 included $244 million and $303 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million as of December 31, 2013 associated with our term loan discussed below.
	(i)	See Note 9 for further discussion related to these instruments.
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments [Table Text Block]	'
	Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.
			30-Sep-14							31-Dec-13
			Carrying				Estimated			Carrying		Estimated
			Amount				Fair Value			Amount		Fair Value
							($ in millions)
	Long-term debt (Level 1)		$	11,523			$	12,347		$	10,501	$	11,557
	Long-term debt (Level 2)		$	59			$	58		$	2,372	$	2,369

Contingencies_and_Commitments_1

Contingencies and Commitments (Tables)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]	'
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
		September 30, 2014
		($ in millions)
	2014	$	616
	2015	1,852
	2016	1,933
	2017	1,951
	2018	1,748
	2019 - 2099	7,672
	Total	$	15,772

Other_Liabilities_Other_Liabil

Other Liabilities Other Liabilities (Tables)	9 Months Ended
	Sep. 30, 2014
Other Liabilities Disclosure [Abstract]	'
Other Current Liabilities [Table Text Block]	'
	Other current liabilities as of September 30, 2014 and December 31, 2013 are detailed below.
			September 30,		December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,401	$	1,409
	Accrued natural gas, oil and NGL drilling and production costs		389		457
	Joint interest prepayments received		382		464
	Accrued compensation and benefits		250		320
	Other accrued taxes		115		161
	Accrued dividends		102		101
	Other		496		599
	Total other current liabilities		$	3,135	$	3,511
Other Long-Term Liabilities [Table Text Block]	'
	Other long-term liabilities as of September 30, 2014 and December 31, 2013 are detailed below.
			September 30,		December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	227	$	250
	CHK C-T ORRI conveyance obligation(b)		139		149
	Financing obligations		30		31
	Unrecognized tax benefits		55		317
	Other		236		237
	Total other long-term liabilities		$	687	$	984
	____________________________________________
	(a)	$13 million and $13 million of the total $240 million and $263 million obligations are recorded in other current liabilities as of September 30, 2014 and December 31, 2013, respectively. See Noncontrolling Interests in Note 7 for further discussion of the transaction.
	(b)	$21 million and $12 million of the total $160 million and $161 million obligations are recorded in other current liabilities as of September 30, 2014 and December 31, 2013, respectively. See Noncontrolling Interests in Note 7 for further discussion of the transaction.

Equity_Tables

Equity (Tables)	9 Months Ended
	Sep. 30, 2014
Equity [Abstract]	'
Common Stock [Table Text Block]	'
	The following is a summary of the changes in our common shares issued during the Current Period and the Prior Period:
			Nine Months Ended
			September 30,
			2014			2013
			(in thousands)
	Shares issued as of January 1		666,192			666,468
	Restricted stock issuances (net of forfeitures)(a)		(2,413	)		684
	Stock option exercises		1,267			321
	Shares issued as of September 30		665,046			667,473
	___________________________________________
	(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 restricted shares of common stock are issued on the grant date of RSAs. We refer to RSAs and RSUs collectively as restricted stock.
Schedule of Stock by Class [Table Text Block]	'
	The following reflects the shares outstanding during the Current Period and the Prior Period and the liquidation preferences of our cumulative convertible preferred stock:
			5.75%				5.75% (A)				4.50%			5.00%
														(2005B)
	Shares outstanding as of January 1, 2014 and 2013 and		1,497				1,100				2,559			2,096
	September 30, 2014 and 2013 (in thousands)
	Liquidation preference per share		$	1,000			$	1,000			$	100		$	100
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	For the Current Period and the Prior Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		3				—				3
	Amounts reclassified from accumulated other comprehensive income		13				(5		)		8
	Net other comprehensive income		16				(5		)		11
	Balance, September 30, 2014		$	(151	)		$	—			$	(151	)
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		13				4				17
	Net other comprehensive income		15				(2		)		13
	Balance, September 30, 2013		$	(174	)		$	5			$	(169	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Three Months Ended
			September 30,
			2014								2013
			Before				After				Before			After
			Tax				Tax				Tax			Tax
			($ in millions)
	Balance, beginning of period		$	(243	)		$	(154	)		$	(286	)	$	(178	)
	Net change in fair value		—				—				3			2
	Gains reclassified to income		5				3				3			2
	Balance, end of period		$	(238	)		$	(151	)		$	(280	)	$	(174	)
			Nine Months Ended
			September 30,
			2014								2013
			Before				After				Before			After
			Tax				Tax				Tax			Tax
			($ in millions)
	Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)	$	(189	)
	Net change in fair value		6				3				3			2
	Losses reclassified to income		25				13				21			13
	Balance, end of period		$	(238	)		$	(151	)		$	(280	)	$	(174	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	'
	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		Affected Line Item		Three Months Ended
	Other Comprehensive		in the Statement		September 30,
	Income (Loss) Components		Where Net Income is Presented		2014				2013
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	3			$	2
	Investments:
	Sale of investment		Net gain on sale of investment		—				(2		)
	Total reclassifications for the period, net of tax				$	3			$	—
	Details About Accumulated		Affected Line Item		Nine Months Ended
	Other Comprehensive		in the Statement		September 30,
	Income (Loss) Components		Where Net Income is Presented		2014				2013
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	13			$	13
	Investments:
	Impairment of investment		Losses on investments		—				6
	Sale of investment		Net gain on sale of investment		(5		)		(2		)
	Total reclassifications for the period, net of tax				$	8			$	17
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	For the Current Period and the Prior Period, the Trust declared and paid the following distributions:
	Production Period		Distribution Date		Cash Distribution				Cash Distribution
					per				per
					Common Unit				Subordinated Unit
	March 2014 - May 2014		August 29, 2014		$	0.5796			$	—
	December 2013 - February 2014		May 30, 2014		$	0.6454			$	—
	September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
	March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
	December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
	September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block]	'
	A summary of the changes in unvested shares of restricted stock during the Current Period is presented below.
			Number of			Weighted Average
			Unvested			Grant Date
			Restricted Shares			Fair Value
			(in thousands)
	Unvested shares as of January 1, 2014		13,400			$	23.38
	Granted		4,882			$	26.09
	Vested		(4,557	)		$	27.58
	Forfeited		(3,279	)		$	28.72
	Unvested shares as of September 30, 2014		10,446			$	21.14
Equity-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]	'
	For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and used the following assumptions to determine the grant date fair value of the PSUs granted in the Current Period:
	Volatility		41.37	%
	Risk-free interest rate		0.76	%
	Dividend yield for value of awards		1.36	%
	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		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
Schedule of Share-Based Compensation, Stock Options, Activity [Table Text Block]	'
	The following table provides information related to stock option activity during the Current Period:
			Number of			Weighted			Weighted		Aggregate
			Shares			Average			Average		Intrinsic
			Underlying			Exercise			Contract		Value(a)
			Options			Price			Life in
						Per Share			Years
			(in thousands)								($ in millions)
	Outstanding at January 1, 2014		5,268			$	19.28		6.66		$	41
	Granted		994			$	24.43
	Exercised		(1,309	)		$	18.75				$	11
	Expired		(28	)		$	18.97
	Forfeited		(313	)		$	21.05
	Outstanding at September 30, 2014		4,612			$	19.53		7.63		$	17
	Exercisable at September 30, 2014		1,133			$	18.71		6.78		$	5
	___________________________________________
	(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 [Table Text Block]	'
	We recognized the following compensation costs related to PSUs during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended							Nine Months Ended
			September 30,							September 30,
			2014				2013			2014				2013
			($ in millions)
	General and administrative expenses		$	(12	)		$	18		$	(2	)		$	28
	Natural gas and oil properties		—				4			3				8
	Natural gas, oil and NGL production expenses		—				1			—				2
	Marketing, gathering and compression expenses		(1		)		2			—				3
	Total		$	(13	)		$	25		$	1			$	41
	We recognized the following compensation costs related to restricted stock and stock options during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended							Nine Months Ended
			September 30,							September 30,
			2014				2013			2014				2013
			($ in millions)
	General and administrative expenses		$	12			$	13		$	36			$	48
	Natural gas and oil properties		6				12			22				45
	Natural gas, oil and NGL production expenses		5				5			13				17
	Marketing, gathering and compression expenses		2				2			5				5
	Oilfield services expenses		—				3			5				8
	Total		$	25			$	35		$	81			$	123
Liability-Classified Share-Based Payment Award Valuation Assumptions [Table Text Block]	'
	For the 2014 awards, the Company utilized the Monte Carlo simulation for the TSR performance measure, and used the following assumptions to determine the grant date fair value of the PSUs granted in the Current Period:
	Volatility		41.37	%
	Risk-free interest rate		0.76	%
	Dividend yield for value of awards		1.36	%
	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		5.9
	Volatility		48.63	%
	Risk-free interest rate		1.93	%
	Dividend yield		1.33	%
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	'
	The following table presents a summary of our PSU awards as of September 30, 2014:
			Units			Fair Value			Fair Value				Liability for
						as of							Vested
						Grant Date							Amount
						($ in millions)
	2012 Awards (a)
	Payable 2015		884,507			$	23		$	21			$	21
	2013 Awards
	Payable 2016		1,701,941			$	35		$	45			$	42
	2014 Awards
	Payable 2017		609,637			$	16		$	10			$	6
	___________________________________________
	(a)	In the Current Period and the Prior Period, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
Liability-Classified Stock-Based Compensation [Table Text Block]	'
	We recognized the following compensation costs related to PSUs during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended							Nine Months Ended
			September 30,							September 30,
			2014				2013			2014				2013
			($ in millions)
	General and administrative expenses		$	(12	)		$	18		$	(2	)		$	28
	Natural gas and oil properties		—				4			3				8
	Natural gas, oil and NGL production expenses		—				1			—				2
	Marketing, gathering and compression expenses		(1		)		2			—				3
	Total		$	(13	)		$	25		$	1			$	41
	We recognized the following compensation costs related to restricted stock and stock options during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended							Nine Months Ended
			September 30,							September 30,
			2014				2013			2014				2013
			($ in millions)
	General and administrative expenses		$	12			$	13		$	36			$	48
	Natural gas and oil properties		6				12			22				45
	Natural gas, oil and NGL production expenses		5				5			13				17
	Marketing, gathering and compression expenses		2				2			5				5
	Oilfield services expenses		—				3			5				8
	Total		$	25			$	35		$	81			$	123

Derivative_and_Hedging_Activit1

Derivative and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Schedule of Derivative Instruments Included in Trading Activities [Table Text Block]	'
	The estimated fair values of our natural gas and oil derivative instrument assets (liabilities) as of September 30, 2014 and December 31, 2013 are provided below.
			30-Sep-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		224			$	27			448			$	(23	)
	Three-way collars		278			41				288			(7		)
	Collars		11			5				—			—
	Call options		193			(183		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		95			(2		)		68			3
	Total natural gas		801			(112		)		1,009			(237		)
	Oil (mmbbl):
	Fixed-price swaps		19.6			113				25.3			(50		)
	Three-way collars		4.4			11				—			—
	Call options		38.3			(179		)		42.5			(265		)
	Basis protection swaps		0.1			—				0.4			1
	Total oil		62.4			(55		)		68.2			(314		)
	Total estimated fair value					$	(167	)					$	(551	)
Schedule Of Derivative Instruments In Condensed Consolidated Balance Sheets [Table Text Block]	'
	The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 on a gross basis and after same-counterparty netting:
			September 30, 2014
	Balance Sheet Classification		Gross Fair Value				Amounts Netted				Net Fair Value Presented
							in Condensed Consolidated				in Condensed Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	Commodity Contracts
	Short-term derivative asset		$	193			$	(93	)		$	100
	Long-term derivative asset		26				(12		)		14
	Short-term derivative liability		(155		)		93				(62		)
	Long-term derivative liability		(231		)		12				(219		)
	Total commodity contracts		(167		)		—				(167		)
	Interest Rate Contracts
	Short-term derivative liability		(7		)		—				(7		)
	Long-term derivative liability		(45		)		—				(45		)
	Total interest rate contracts		(52		)		—				(52		)
	Foreign Currency Contracts(a)
	Long-term derivative liability		(30		)		—				(30		)
	Total foreign currency contracts		(30		)		—				(30		)
	Total Derivatives		$	(249	)		$	—			$	(249	)
			December 31, 2013
	Balance Sheet Classification		Gross Fair Value				Amounts Netted				Net Fair Value Presented
							in Condensed Consolidated				in Condensed Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	Commodity Contracts
	Short-term derivative asset		$	29			$	(29	)		$	—
	Long-term derivative asset		11				(9		)		2
	Short-term derivative liability		(231		)		29				(202		)
	Long-term derivative liability		(362		)		9				(353		)
	Total commodity contracts		(553		)		—				(553		)
	Interest Rate Contracts
	Short-term derivative liability		(6		)		—				(6		)
	Long-term derivative liability		(92		)		—				(92		)
	Total interest rate contracts		(98		)		—				(98		)
	Foreign Currency Contracts(a)
	Long-term derivative asset		2				—				2
	Total foreign currency contracts		2				—				2
	Total Derivatives		$	(649	)		$	—			$	(649	)
	____________________________________________
	(a)	Designated as cash flow hedging instruments.
Schedule of Derivative Instruments [Table Text Block]	'
	The components of natural gas, oil and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2014				2013				2014				2013
			($ in millions)
	Natural gas, oil and NGL sales		$	1,777			$	1,839			$	5,842			$	5,303
	Gains (losses) on undesignated natural gas and oil		569				(250		)		(5		)		162
	derivatives
	Losses on terminated cash flow hedges		(5		)		(3		)		(25		)		(21		)
	Total natural gas, oil and NGL sales		$	2,341			$	1,586			$	5,812			$	5,444
Interest Income And Interest Expense Disclosure [Table Text Block]	'
	The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2014				2013				2014				2013
			($ in millions)
	Interest expense on senior notes		$	170			$	180			$	534			$	560
	Interest expense on term loans		—				29				36				87
	Amortization of loan discount, issuance costs and other		9				21				44				70
	Interest expense on credit facilities		6				8				22				30
	Gains on terminated fair value hedges		—				—				(2		)		—
	(Gains) losses on undesignated interest rate derivatives		2				(3		)		(48		)		51
	Capitalized interest		(170		)		(195		)		(504		)		(634		)
	Total interest expense		$	17			$	40			$	82			$	164
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	For the Current Period and the Prior Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	Other comprehensive income before reclassifications		3				—				3
	Amounts reclassified from accumulated other comprehensive income		13				(5		)		8
	Net other comprehensive income		16				(5		)		11
	Balance, September 30, 2014		$	(151	)		$	—			$	(151	)
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		13				4				17
	Net other comprehensive income		15				(2		)		13
	Balance, September 30, 2013		$	(174	)		$	5			$	(169	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Three Months Ended
			September 30,
			2014								2013
			Before				After				Before				After
			Tax				Tax				Tax				Tax
			($ in millions)
	Balance, beginning of period		$	(243	)		$	(154	)		$	(286	)		$	(178	)
	Net change in fair value		—				—				3				2
	Gains reclassified to income		5				3				3				2
	Balance, end of period		$	(238	)		$	(151	)		$	(280	)		$	(174	)
			Nine Months Ended
			September 30,
			2014								2013
			Before				After				Before				After
			Tax				Tax				Tax				Tax
			($ in millions)
	Balance, beginning of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)
	Net change in fair value		6				3				3				2
	Losses reclassified to income		25				13				21				13
	Balance, end of period		$	(238	)		$	(151	)		$	(280	)		$	(174	)
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'
	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
			Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	As of September 30, 2014
	Derivative Assets (Liabilities):
	Commodity assets		$	—			$	162			$	57			$	219
	Commodity liabilities		—				(26		)		(362		)		(388		)
	Interest rate liabilities		—				(52		)		—				(52		)
	Foreign currency liability		—				(30		)		—				(30		)
	Total derivatives		$	—			$	54			$	(305	)		$	(251	)
	As of December 31, 2013
	Derivative Assets (Liabilities):
	Commodity assets		$	—			$	25			$	15			$	40
	Commodity liabilities		—				(100		)		(493		)		(593		)
	Interest rate liabilities		—				(98		)		—				(98		)
	Foreign currency assets		—				2				—				2
	Total derivatives		$	—			$	(171	)		$	(478	)		$	(649	)
	The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
			Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	As of September 30, 2014
	Financial Assets (Liabilities):
	Other current assets		$	57			$	—			$	—			$	57
	Other current liabilities		(58		)		—				—				(58		)
	Total		$	(1	)		$	—			$	—			$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets		$	80			$	—			$	—			$	80
	Other current liabilities		(82		)		—				—				(82		)
	Total		$	(2	)		$	—			$	—			$	(2	)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	'
	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.
			Derivatives
			Commodity				Interest Rate
			($ in millions)
	Beginning Balance as of January 1, 2014		$	(478	)		$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		53				—
	Total purchases, issuances, sales and settlements:
	Settlements		124				—
	Transfers(b)		(4		)		—
	Ending Balance as of September 30, 2014		$	(305	)		$	—
	Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		338				(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—				1
	Settlements		93				—
	Ending Balance as of September 30, 2013		$	(585	)		$	—
	___________________________________________
	(a)		Natural Gas, Oil and								Interest Expense
			NGL Sales
			2014				2013				2014				2013
			($ in millions)
	Total gains (losses) included in earnings for the period		$	53			$	338			$	—			$	(1	)
	Change in unrealized gains (losses) related to		$	60			$	327			$	—			$	—
	assets still held at reporting date
	(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 [Table Text Block]	'
	The following table presents quantitative information about Level 3 inputs used in the fair value measurement of our commodity derivative contracts at fair value as of September 30, 2014:
	Instrument		Unobservable		Range		Weighted		Fair Value
	Type		Input				Average		September 30, 2014(a)
									($ in millions)
	Oil trades		Oil price volatility curves		12.45% - 20.94%		15.96%		$	(168	)
	Natural gas trades		Natural gas price volatility		19.02% - 52.92%		28.47%		$	(137	)
			curves
	___________________________________________
	(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_T1

Natural Gas and Oil Property Transactions (Tables)	9 Months Ended
	Sep. 30, 2014
Property, Plant and Equipment [Abstract]	'
VPP Transactions [Table Text Block]	'
	As of September 30, 2014, our outstanding VPPs consisted of the following:
									Volume Sold
	VPP #		Date of VPP	Location		Proceeds			Natural Gas		Oil		NGL		Total
						($ in millions)			(bcf)		(mmbbl)		(mmbbl)		(bcfe)
	10		Mar-12	Anadarko Basin Granite		$	744		87		3		9.2		160
				Wash
	9		May-11	Mid-Continent		853			138		1.7		4.8		177
	8		September 2010	Barnett Shale		1,150			390		—		—		390
	6		February 2010	East Texas and NW		180			44		0.3		—		46
				Louisiana
	4		December 2008	Anadarko and Arkoma		412			95		0.5		—		98
				Basins
	3		Aug-08	Anadarko Basin		600			93		—		—		93
	2		May-08	Texas, Oklahoma and		622			94		—		—		94
				Kansas
	1		December 2007	Kentucky and West		1,100			208		—		—		208
				Virginia
						$	5,661		1,149		5.5		14		1,266
VPP Volumes Produced During Period [Table Text Block]	'
	The volumes produced on behalf of our VPP buyers for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:
			Three Months Ended September 30, 2014									Three Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL		Total		Natural Gas		Oil		NGL	Total
			(bcf)		(mbbl)			(mbbl)		(bcfe)		(bcf)		(mbbl)		(mbbl)	(bcfe)
	10		2.6		98			314.5		5		3.3		131		371.9	6.3
	9		3.8		46.1			101.5		4.7		4.2		52.3		112.2	5.2
	8		14.8		—			—		14.8		16.7		—		—	16.7
	6		1.1		6			—		1.1		1.2		6		—	1.2
	5(a)		1.2		4.2			—		1.2		1.9		6.7		—	1.9
	4		2.2		11.9			—		2.3		2.5		13.5		—	2.6
	3		1.8		—			—		1.8		2		—		—	2
	2		1.1		—			—		1.1		2.5		—		—	2.5
	1		3.4		—			—		3.4		3.5		—		—	3.5
			32		166.2			416		35.4		37.8		209.5		484.1	41.9
	__________________________________________
	(a)	In the Current Quarter, we divested the properties associated with VPP #5.
			Nine Months Ended September 30, 2014									Nine Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL		Total		Natural Gas		Oil		NGL	Total
			(bcf)		(mbbl)			(mbbl)		(bcfe)		(bcf)		(mbbl)		(mbbl)	(bcfe)
	10		8.1		310			989.6		15.8		10.3		426		1,158.60	19.8
	9		11.7		142.6			311.9		14.4		12.9		162.7		346.4	16
	8		45.7		—			—		45.7		52		—		—	52
	6		3.3		18			—		3.4		3.6		18		—	3.6
	5(a)		4.6		16.5			—		4.7		5.8		18.9		—	5.8
	4		6.8		36.5			—		7		7.7		41.5		—	8
	3		5.5		—			—		5.5		6.1		—		—	6.1
	2		5.1		—			—		5.1		7.8		—		—	7.8
	1		10.4		—			—		10.4		10.9		—		—	10.9
			101.2		523.6			1,301.50		112		117.1		667.1		1,505.00	130
	__________________________________________
	(a)	In the Current Quarter, we divested the properties associated with VPP #5.
VPP Volumes Remaining to be Delivered [Table Text Block]	'
	The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2014 were as follows:
				Volume Remaining as of September 30, 2014
	VPP #		Term Remaining	Natural Gas			Oil		NGL		Total
			(in months)	(bcf)			(mmbbl)		(mmbbl)		(bcfe)
	10		89	40.5			1.4		5		78.9
	9		77	77			0.9		2		94.5
	8		11	50.9			—		—		50.9
	6		64	18.1			0.1		—		18.9
	4		27	17.5			0.1		—		18.1
	3		58	25.6			—		—		25.6
	2		55	14.9			—		—		14.9
	1		99	94.9			—		—		94.9
				339.4			2.5		7		396.7

Investments_Tables

Investments (Tables)	9 Months Ended
	Sep. 30, 2014
Investments [Abstract]	'
Equity Method Investments [Table Text Block]	'
	A summary of our investments, including our approximate ownership percentage and carrying value as of September 30, 2014 and December 31, 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	September 30,	December 31,	September 30,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	110	$	138
	Sundrop Fuels, Inc.	Equity	56%	56%	132		135
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Other	—	—%	—%	12		61
	Total investments				$	254	$	477

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	9 Months Ended
	Sep. 30, 2014
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]	'
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]	'
	A summary by asset class of (gains) or losses on sales of fixed assets for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2014			2013			2014			2013
		($ in millions)
	Natural gas compressors	$	(75	)	$	—		$	(195	)	$	—
	Gathering systems and treating plants	(5		)	(132		)	8			(311		)
	Oilfield services equipment	—			—			(7		)	1
	Buildings and land	(6		)	1			(5		)	24
	Other	—			(1		)	(2		)	(4		)
	Total net gains on sales of fixed assets	$	(86	)	$	(132	)	$	(201	)	$	(290	)
Disclosure of Long Lived Assets Held-for-Sale [Table Text Block]	'
	A summary of the assets held for sale on our condensed consolidated balance sheets as of September 30, 2014 and December 31, 2013 is detailed below.
		September 30,			December 31,
		2014			2013
		($ in millions)
	Buildings and land, net of accumulated depreciation	$	101		$	405
	Compressors, net of accumulated depreciation	—			285
	Oilfield services equipment, net of accumulated depreciation	—			29
	Gathering systems and treating plants, net of accumulated depreciation	—			11
	Property and equipment held for sale, net	$	101		$	730

Impairments_of_Fixed_Assets_an2

Impairments of Fixed Assets and Other (Tables)	9 Months Ended
	Sep. 30, 2014
Asset Impairment Charges [Abstract]	'
Details of Impairment of Long-Lived Assets Held and Used by Asset [Table Text Block]	'
	A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2014		2013		2014		2013
		($ in millions)
	Natural gas compressors	$	11	$	—	$	11	$	—
	Gathering systems and treating plants	—		21		10		22
	Oilfield services equipment	—		24		23		27
	Buildings and land	4		8		9		247
	Other	—		32		22		47
	Total impairments of fixed assets and other	$	15	$	85	$	75	$	343

Recovered_Sheet1

Restructuring and other Termination Benefits (Tables)	9 Months Ended
	Sep. 30, 2014
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Costs [Table Text Block]	'
	Below is a summary of our restructuring and other termination costs for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended					Nine Months Ended
			September 30,					September 30,
			2014			2013		2014			2013
			($ in millions)
	Oilfield services spin-off costs:
	Transaction costs		$	3		$	—	$	17		$	—
	Stock-based compensation adjustments for		—			—		5			—
	Chesapeake employees
	Stock-based compensation forfeitures for SSE		—			—		(10		)	—
	employees
	Debt extinguishment costs		—			—		3			—
	Total oilfield services spin-off costs		3			—		15			—
	Restructuring charges under workforce reduction plan:
	Salary expense		—			5		—			5
	Acceleration of stock-based compensation		—			25		—			25
	Other termination benefits		—			1		—			1
	Total restructuring changes under workforce		—			31		—			31
	reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense		—			—		—			11
	Acceleration of 2008 performance bonus clawback		—			—		—			11
	Acceleration of stock-based compensation		—			—		—			22
	Acceleration of performance share unit awards(a)		(7		)	3		(5		)	16
	Estimated aircraft usage benefits		—			—		—			7
	Total termination benefits provided to		(7		)	3		(5		)	67
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			—		—			32
	Acceleration of stock-based compensation		—			1		—			28
	Other termination benefits		—			—		—			3
	Total termination benefits provided to VSP		—			1		—			63
	participants
	Other termination benefits(a)		(10		)	28		2			42
	Total restructuring and other termination costs		$	(14	)	$	63	$	12		$	203
	____________________________________________
	(a)	The Current Quarter and Current Period amounts are primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 8.

Fair_Value_Measurements_Fair_V

Fair Value Measurements Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2014
Fair Value Disclosures [Abstract]	'
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	'
	The following table provides information for financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
		Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of September 30, 2014
	Derivative Assets (Liabilities):
	Commodity assets	$	—		$	162		$	57		$	219
	Commodity liabilities	—			(26		)	(362		)	(388		)
	Interest rate liabilities	—			(52		)	—			(52		)
	Foreign currency liability	—			(30		)	—			(30		)
	Total derivatives	$	—		$	54		$	(305	)	$	(251	)
	As of December 31, 2013
	Derivative Assets (Liabilities):
	Commodity assets	$	—		$	25		$	15		$	40
	Commodity liabilities	—			(100		)	(493		)	(593		)
	Interest rate liabilities	—			(98		)	—			(98		)
	Foreign currency assets	—			2			—			2
	Total derivatives	$	—		$	(171	)	$	(478	)	$	(649	)
	The following table provides fair value measurement information for the above-noted financial assets (liabilities) measured at fair value on a recurring basis as of September 30, 2014 and December 31, 2013:
		Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	As of September 30, 2014
	Financial Assets (Liabilities):
	Other current assets	$	57		$	—		$	—		$	57
	Other current liabilities	(58		)	—			—			(58		)
	Total	$	(1	)	$	—		$	—		$	(1	)
	As of December 31, 2013
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—		$	—		$	80
	Other current liabilities	(82		)	—			—			(82		)
	Total	$	(2	)	$	—		$	—		$	(2	)

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2014
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]	'
Schedule of Segment Reporting Information, by Segment [Table Text Block]	'
	The following table presents selected financial information for Chesapeake’s operating segments:
		Exploration		Marketing,			Former			Other			Intercompany			Consolidated
		and		Gathering			Oilfield						Eliminations			Total
		Production		and			Services
				Compression
		($ in millions)
	Three Months Ended
	September 30, 2014:
	Revenues	$	2,341	$	5,512		$	—		$	—		$	(2,150	)	$	5,703
	Intersegment revenues	—		(2,150		)	—			—			2,150			—
	Total revenues	$	2,341	$	3,362		$	—		$	—		$	—		$	5,703
	Income (Loss) Before	$	987	$	113		$	—		$	(63	)	$	92		$	1,129
	Income Taxes
	Three Months Ended
	September 30, 2013:
	Revenues	$	1,586	$	5,034		$	551		$	4		$	(2,308	)	$	4,867
	Intersegment revenues	—		(2,002		)	(306		)	—			2,308			—
	Total revenues	$	1,586	$	3,032		$	245		$	4		$	—		$	4,867
	Income (Loss) Before	$	430	$	128		$	(37	)	$	(48	)	$	(86	)	$	387
	Income Taxes
	Nine Months Ended
	September 30, 2014:
	Revenues	$	5,812	$	16,289		$	1,060		$	30		$	(7,290	)	$	15,901
	Intersegment revenues	—		(6,746		)	(544		)	—			7,290			—
	Total revenues	$	5,812	$	9,543		$	516		$	30		$	—		$	15,901
	Income (Loss) Before	$	2,089	$	325		$	(16	)	$	(24	)	$	(128	)	$	2,246
	Income Taxes
	Nine Months Ended
	September 30, 2013:
	Revenues	$	5,444	$	12,553		$	1,677		$	27		$	(6,736	)	$	12,965
	Intersegment revenues	—		(5,682		)	(1,041		)	(13		)	6,736			—
	Total revenues	$	5,444	$	6,871		$	636		$	14		$	—		$	12,965
	Income (Loss) Before	$	654	$	395		$	(12	)	$	808		$	(284	)	$	1,561
	Income Taxes
	As of
	September 30, 2014:
	Total Assets	$	34,876	$	2,420		$	—		$	4,357		$	(1,135	)	$	40,518
	As of
	December 31, 2013:
	Total Assets	$	35,341	$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule of Condensed Balance Sheet [Table Text Block]	'
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF SEPTEMBER 30, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	13		$	—		$	90		$	(13	)	$	90
	Restricted cash		—			—			38			—			38
	Other		73			2,737			191			—			3,001
	Intercompany receivable, net		24,366			—			—			(24,366		)	—
	Total Current Assets		24,452			2,737			319			(24,379		)	3,129
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			30,739			2,999			499			34,237
	Other property and equipment, net		—			2,309			5			—			2,314
	Property and equipment held for		—			101			—			—			101
	sale, net
	Total Property and Equipment,		—			33,149			3,004			499			36,652
	Net
	LONG-TERM ASSETS:
	Other assets		105			604			28			—			737
	Investments in subsidiaries and		3,805			686			—			(4,491		)	—
	intercompany advances
	TOTAL ASSETS		$	28,362		$	37,176		$	3,351		$	(28,371	)	$	40,518
	CURRENT LIABILITIES:
	Current liabilities		$	247		$	5,308		$	68		$	(21	)	$	5,602
	Intercompany payable, net		—			23,807			703			(24,510		)	—
	Total Current Liabilities		247			29,115			771			(24,531		)	5,602
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,533			59			—			—			11,592
	Deferred income tax liabilities		132			3,305			713			135			4,285
	Other long-term liabilities		130			892			386			—			1,408
	Total Long-Term Liabilities		11,795			4,256			1,099			135			17,285
	EQUITY:
	Chesapeake stockholders’ equity		16,320			3,805			1,481			(5,286		)	16,320
	Noncontrolling interests		—			—			—			1,311			1,311
	Total Equity		16,320			3,805			1,481			(3,975		)	17,631
	TOTAL LIABILITIES AND EQUITY		$	28,362		$	37,176		$	3,351		$	(28,371	)	$	40,518
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	799		$	—		$	39		$	(1	)	$	837
	Restricted cash		—			—			82			(7		)	75
	Other		103			2,411			578			(348		)	2,744
	Intercompany receivable, net		25,357			—			—			(25,357		)	—
	Total Current Assets		26,259			2,411			699			(25,713		)	3,656
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,295			3,113			185			32,593
	Other property and equipment, net		—			2,360			1,452			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			32,356			4,594			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,161			96			(376		)	992
	Investments in subsidiaries and		2,361			(262		)	—			(2,099		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,666		$	5,389		$	(28,004	)	$	41,782
	CURRENT LIABILITIES:
	Current liabilities		$	300		$	5,227		$	344		$	(356	)	$	5,515
	Intercompany payable, net		—			24,775			558			(25,333		)	—
Total Current Liabilities		300			30,002			902			(25,689		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,281			830			87			3,407
Other long-term liabilities		396			1,022			788			(372		)	1,834
Total Long-Term Liabilities		12,436			3,303			2,673			(285		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,361			1,814			(4,175		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,361			1,814			(2,030		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,666		$	5,389		$	(28,004	)	$	41,782
Schedule of Condensed Income Statement [Table Text Block]	'
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED SEPTEMBER 30, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	2,085		$	256		$	—		$	2,341
	Marketing, gathering and compression		—			3,361			1			—			3,362
	Oilfield services		—			—			—			—			—
	Total Revenues		—			5,446			257			—			5,703
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			284			14			—			298
	Production taxes		—			59			3			—			62
	Marketing, gathering and compression		—			3,368			1			—			3,369
	Oilfield services		—			—			—			—			—
	General and administrative		—			57			3			—			60
	Restructuring and other termination costs		—			(14		)	—			—			(14		)
	Provision for legal contingencies		—			100			—			—			100
	Natural gas, oil and NGL depreciation,		—			599			82			7			688
	depletion and amortization
	Depreciation and amortization of other		—			37			—			—			37
	assets
	Impairment of natural gas and oil properties		—			—			104			(104		)	—
	Impairments of fixed assets and other		—			15			—			—			15
	Net gains on sales of fixed assets		—			(86		)	—			—			(86		)
	Total Operating Expenses		—			4,419			207			(97		)	4,529
	INCOME FROM OPERATIONS		—			1,027			50			97			1,174
	OTHER INCOME (EXPENSE):
	Interest expense		(178		)	(11		)	—			172			(17		)
	Losses on investments		—			(27		)	—			—			(27		)
	Other income (expense)		56			120			(4		)	(173		)	(1		)
	Equity in net earnings of subsidiary		737			(2		)	—			(735		)	—
	Total Other Income (Expense)		615			80			(4		)	(736		)	(45		)
	INCOME BEFORE INCOME TAXES		615			1,107			46			(639		)	1,129
	INCOME TAX EXPENSE (BENEFIT)		(47		)	429			18			37			437
	NET INCOME		662			678			28			(676		)	692
	Net income attributable to		—			—			—			(30		)	(30		)
	noncontrolling interests
	NET INCOME ATTRIBUTABLE		662			678			28			(706		)	662
	TO CHESAPEAKE
	Other comprehensive income		—			3			—			—			3
	COMPREHENSIVE INCOME		$	662		$	681		$	28		$	(706	)	$	665
	ATTRIBUTABLE TO CHESAPEAKE
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED SEPTEMBER 30, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	1,340		$	245		$	1		$	1,586
	Marketing, gathering and compression		—			3,031			1			—			3,032
	Oilfield services		—			57			464			(272		)	249
	Total Revenues		—			4,428			710			(271		)	4,867
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			262			20			—			282
	Production taxes		—			60			2			—			62
	Marketing, gathering and compression		—			3,009			—			—			3,009
	Oilfield services		—			70			385			(244		)	211
	General and administrative		—			97			24			(1		)	120
	Restructuring and other termination costs		—			63			—			—			63
	Natural gas, oil and NGL depreciation,		—			549			103			—			652
depletion and amortization
Depreciation and amortization of other		—			45			71			(37		)	79
assets
Impairment of natural gas and oil		—			—			99			(99		)	—
properties
Impairments of fixed assets and other		—			31			54			—			85
Net gains on sales of fixed assets		—			(133		)	—			1			(132		)
Total Operating Expenses		—			4,053			758			(380		)	4,431
INCOME FROM OPERATIONS		—			375			(48		)	109			436
OTHER INCOME (EXPENSE):
Interest expense		(207		)	(27		)	(21		)	215			(40		)
Losses on investments		—			(22		)	—			—			(22		)
Net gain on sales of investments		—			3			—			—			3
Other income		208			44			2			(244		)	10
Equity in net earnings (losses) of		201			(87		)	—			(114		)	—
subsidiary
Total Other Income (Expense)		202			(89		)	(19		)	(143		)	(49		)
INCOME BEFORE INCOME TAXES		202			286			(67		)	(34		)	387
INCOME TAX EXPENSE (BENEFIT)		—			142			(25		)	30			147
NET INCOME (LOSS)		202			144			(42		)	(64		)	240
Net income attributable to		—			—			—			(38		)	(38		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		202			144			(42		)	(102		)	202
TO CHESAPEAKE (LOSS)
Other comprehensive income (loss)		2			1			(2		)	—			1
COMPREHENSIVE INCOME		$	204		$	145		$	(44	)	$	(102	)	$	203
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	5,100		$	715		$	(3	)	$	5,812
Marketing, gathering and compression		—			9,539			4			—			9,543
Oilfield services		—			40			984			(478		)	546
Total Revenues		—			14,679			1,703			(481		)	15,901
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			818			50			—			868
Production taxes		—			177			8			—			185
Marketing, gathering and compression		—			9,512			3			—			9,515
Oilfield services		—			54			769			(392		)	431
General and administrative		—			176			53			—			229
Restructuring and other termination costs		—			9			3			—			12
Provision for legal contingencies		—			100			—			—			100
Natural gas, oil and NGL depreciation,		—			1,750			211			16			1,977
depletion and amortization
Depreciation and amortization of other		—			116			142			(64		)	194
assets
Impairment of natural gas and oil properties		—			—			202			(202		)	—
Impairments of fixed assets and other		—			52			23			—			75
Net gains on sales of fixed assets		—			(194		)	(7		)	—			(201		)
Total Operating Expenses		—			12,570			1,457			(642		)	13,385
INCOME FROM OPERATIONS		—			2,109			246			161			2,516
OTHER INCOME (EXPENSE):
Interest expense		(524		)	(14		)	(42		)	498			(82		)
Losses on investments		—			(69		)	(5		)	2			(72		)
Net gain on sales of investments		—			67			—			—			67
Losses on purchases of debt		(195		)	—			—			—			(195		)
Other income (loss)		535			12			(2		)	(533		)	12
Equity in net earnings of subsidiary		1,391			11			—			(1,402		)	—
Total Other Income (Expense)		1,207			7			(49		)	(1,435		)	(270		)
INCOME BEFORE INCOME TAXES		1,207			2,116			197			(1,274		)	2,246
INCOME TAX EXPENSE (BENEFIT)		(70		)	804			76			49			859
NET INCOME		1,277			1,312			121			(1,323		)	1,387
Net income attributable to		—			—			—			(110		)	(110		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		1,277			1,312			121			(1,433		)	1,277
TO CHESAPEAKE
Other comprehensive income		3			8			—			—			11
COMPREHENSIVE INCOME		$	1,280		$	1,320		$	121		$	(1,433	)	$	1,288
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,903		$	532		$	9		$	5,444
Marketing, gathering and compression		—			6,861			10			—			6,871
Oilfield services		—			172			1,398			(920		)	650
Total Revenues		—			11,936			1,940			(911		)	12,965
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			833			44			—			877
Production taxes		—			167			6			—			173
Marketing, gathering and compression		—			6,776			5			—			6,781
Oilfield services		—			216			1,101			(774		)	543
General and administrative		—			267			69			—			336
Restructuring and other termination costs		—			200			3			—			203
Natural gas, oil and NGL depreciation,		—			1,729			216			—			1,945
depletion and amortization
Depreciation and amortization of other		—			142			210			(118		)	234
assets
Impairment of natural gas and oil		—			—			260			(260		)	—
properties
Impairments of fixed assets and other		—			282			61			—			343
Net gains on sales of fixed assets		—			(291		)	—			1			(290		)
Total Operating Expenses		—			10,321			1,975			(1,151		)	11,145
INCOME (LOSS) FROM OPERATIONS		—			1,615			(35		)	240			1,820
OTHER INCOME (EXPENSE):
Interest expense		(703		)	(70		)	(63		)	672			(164		)
Losses on investments		—			(36		)	—			—			(36		)
Net gain on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	—			—			—			(70		)
Other income		651			120			7			(760		)	18
Equity in net earnings (losses) of		916			(241		)	—			(675		)	—
subsidiary
Total Other Income (Expense)		794			(234		)	(56		)	(763		)	(259		)
INCOME (LOSS) BEFORE INCOME TAXES		794			1,381			(91		)	(523		)	1,561
INCOME TAX EXPENSE (BENEFIT)		(46		)	617			(35		)	58			594
NET INCOME (LOSS)		840			764			(56		)	(581		)	967
Net income attributable to		—			—			—			(127		)	(127		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		840			764			(56		)	(708		)	840
TO CHESAPEAKE
Other comprehensive income (loss)		2			12			(1		)	—			13
COMPREHENSIVE INCOME		$	842		$	776		$	(57	)	$	(708	)	$	853
ATTRIBUTABLE TO CHESAPEAKE
Schedule of Condensed Cash Flow Statement [Table Text Block]	'
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	NINE MONTHS ENDED SEPTEMBER 30, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	3,188		$	617		$	—		$	3,805
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Drilling and completion costs		—			(2,847		)	(338		)	—			(3,185		)
	Acquisitions of proved and unproved properties		—			(1,020		)	(3		)	—			(1,023		)
	Proceeds from divestitures of proved and unproved properties		—			726			(3		)	—			723
	Additions to other property and equipment		—			(423		)	(252		)	—			(675		)
	Other investing activities		—			1,143			60			19			1,222
	Net Cash Used In Investing		—			(2,421		)	(536		)	19			(2,938		)
	Activities
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities borrowings		—			2,856			717			—			3,573
	Payments on credit facilities borrowings		—			(2,797		)	(1,099		)	—			(3,896		)
	Proceeds from issuance of senior notes, net of discount and offering costs		2,966			—			494			—			3,460
	Proceeds from issuance of oilfield services term loan, net of issuance costs		—			—			394			—			394
	Cash paid to purchase debt		(3,362		)	—			—			—			(3,362		)
	Other financing activities		(293		)	(1,300		)	(159		)	(31		)	(1,783		)
	Intercompany advances, net		(97		)	474			(377		)	—			—
	Net Cash Provided By (Used In)		(786		)	(767		)	(30		)	(31		)	(1,614		)
	Financing Activities
	Net increase (decrease) in cash and cash		(786		)	—			51			(12		)	(747		)
	equivalents
	Cash and cash equivalents, beginning of		799			—			39			(1		)	837
	period
	Cash and cash equivalents, end of period		$	13		$	—		$	90		$	(13	)	$	90
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	NINE MONTHS ENDED SEPTEMBER 30, 2013
	($ in millions)
			Parent(a)			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries(a)			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	3,321		$	298		$	(33	)	$	3,586
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Drilling and completion costs		—			(3,826		)	(644		)	—			(4,470		)
	Acquisitions of proved and unproved properties		—			(402		)	(409		)	—			(811		)
	Proceeds from divestitures of proved and unproved properties		—			2,736			53			—			2,789
	Additions to other property and equipment		—			(418		)	(221		)	—			(639		)
	Other investing activities		—			67			757			260			1,084
	Net Cash Used In Investing		—			(1,843		)	(464		)	260			(2,047		)
	Activities
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities borrowings		—			6,311			825			—			7,136
	Payments on credit facilities borrowings		—			(6,310		)	(958		)	—			(7,268		)
	Proceeds from issuance of senior notes, net of discount and offering costs		2,274			—			—			—			2,274
	Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
	Proceeds from sales of noncontrolling interests		—			5			—			—			5
	Other financing activities		(374		)	(297		)	46			(220		)	(845		)
	Intercompany advances, net		979			(1,187		)	208			—			—
	Net Cash Provided By (Used		738			(1,478		)	121			(220		)	(839		)
	In) Financing Activities
	Net increase (decrease) in cash and cash		738			—			(45		)	7			700
	equivalents
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	966		$	—		$	14		$	7		$	987
___________________________________________
(a)	We have revised the amounts presented as cash and cash equivalents in the Guarantor Subsidiaries and Parent columns to properly reflect the cash of the Parent. As of December 31, 2012 and September 30, 2013, $228 million and $966 million, respectively, were incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

SpinOff_of_Oilfield_Services_B1

Spin-Off of Oilfield Services Business Spin-Off of Oilfield Services Business Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

6 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Apr. 24, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Jun. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Jun. 30, 2014

Drilling Rig Leases [Member]

Minimum [Member]

Maximum [Member]

Retained Earnings [Member]

Retained Earnings [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

Minimum [Member]

Maximum [Member]

Drilling Rig Leases [Member]

Minimum [Member]

Maximum [Member]

Secured Debt [Member]

Senior Notes [Member]

Spinoff [Member]

Spinoff [Member]

Spinoff [Member]

Spinoff [Member]

Seven Seven Energy Inc. Revolving Bank Credit Facility [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

6.5% Senior Notes Due 2022 [Member]

Assets Disposed of by Method Other than Sale, in Period of Disposition [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

'

'

'

'

'

'

'

'

'

'

Borrowing capacity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$275

Long-term Debt, Gross

1,500

'

1,500

'

'

'

'

'

'

3,000

3,000

50

75

'

'

'

'

400

500

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6.50%

'

'

'

'

'

General Partner Distributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

391

'

'

'

'

'

Operating Leases, Future Minimum Payment Due

'

'

'

'

449

'

'

'

'

'

'

'

'

'

356

'

'

'

'

'

'

'

'

'

Spin-off of oilfield services business (Note 2)

'

'

'

'

'

'

'

-270

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease Term

'

'

'

'

'

'3 months

'3 years

'

'

'

'

'

'

'

'

'3 months

'3 years

'

'

'

'

'

'

'

Restructuring and other termination costs

($14)

$63

$12

$203

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$3

$0

$15

$0

'

Earnings_Per_Share_Antidilutiv

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
5.75% Cumulative Convertible Preferred Stock [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	$21	$21	$64	$64
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	59	56	59	56
5.75% Cumulative Convertible Preferred Stock Series A [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	16	16	47	47
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	42	39	42	40
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	3	3	8	8
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	5	6	5
4.50% Cumulative Convertible Preferred Stock [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	3	3	9	9
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	6	6
Restricted Stock [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	$3	$3	$14	$14
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3	2	3	3

Debt_LongTerm_Debt_Table_Detai

Debt - Long-Term Debt Table (Details) (USD $)

9 Months Ended

9 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Apr. 24, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2006

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2006

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Interest Rate Contract [Member]

Interest Rate Contract [Member]

2.75% Contingent Convertible Senior Notes Due 2035 [Member]

2.5% Contingent Convertible Senior Notes due 2037 [Member]

2.25% Contingent Convertible Senior Notes Due 2038 [Member]

Unsecured Debt [Member]

Unsecured Debt [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Line of Credit [Member]

Senior Secured Term Loan Due 2017 [Member]

Senior Secured Term Loan Due 2017 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

3.25% Senior Notes due 2016 [Member]

3.25% Senior Notes due 2016 [Member]

3.25% Senior Notes due 2016 [Member]

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

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

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

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

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

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

6.5% Senior Notes Due 2017 [Member]

6.5% Senior Notes Due 2017 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

7.25% Senior Notes Due 2018 [Member]

7.25% Senior Notes Due 2018 [Member]

Floating Rate Senior Notes due 2019 [Member]

Floating Rate Senior Notes due 2019 [Member]

6.625% Senior Notes Due 2019 [Member]

6.625% Senior Notes Due 2019 [Member]

6.625% Senior Notes Due 2020 [Member]

6.625% Senior Notes Due 2020 [Member]

6.875% Senior Notes Due 2020 [Member]

6.875% Senior Notes Due 2020 [Member]

6.125% Senior Notes Due 2021 [Member]

6.125% Senior Notes Due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

4.875% Senior Notes due 2022 [Member]

4.875% Senior Notes due 2022 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

2.75% Contingent Convertible Senior Notes Due 2035 [Member]

2.75% Contingent Convertible Senior Notes Due 2035 [Member]

2.5% Contingent Convertible Senior Notes due 2037 [Member]

2.5% Contingent Convertible Senior Notes due 2037 [Member]

2.25% Contingent Convertible Senior Notes Due 2038 [Member]

2.25% Contingent Convertible Senior Notes Due 2038 [Member]

Corporate Revolving Bank Credit Facility [Member]

Corporate Revolving Bank Credit Facility [Member]

Oilfield Services Revolving Bank Credit Facility [Member]

Oilfield Services Revolving Bank Credit Facility [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Union Bank N.A.

Union Bank N.A.

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

$1,500

'

$10

$13

'

'

'

$0

$2,000

$3,000

$3,000

'

$0

$1,265

$500

$500

$500

$435

$473

$344

$435

'

'

$660

$660

$0

$97

'

$669

$669

$1,500

$0

$0

$650

$1,300

$1,300

$500

$500

$1,000

$1,000

$700

$700

$700

$1,500

$0

$1,100

$1,100

$1,100

$396

$396

$1,168

$1,168

$347

$347

$59

$0

$0

$405

Debt Instrument, Unamortized Discount

-252

-357

'

'

'

'

'

'

-33

-244

'

-303

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt, net

$11,592

$12,886

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$125

'

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.2631

1.3743

1.3325

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

9.50%

'

3.25%

'

3.25%

'

'

'

6.25%

'

'

6.50%

'

6.88%

'

6.88%

7.25%

'

'

'

6.63%

'

6.63%

'

6.88%

'

6.13%

'

5.38%

'

5.38%

4.88%

'

5.75%

'

5.75%

2.75%

'

2.50%

'

2.25%

'

'

'

'

'

Percentage Of Principal Amount Of Notes For Repurchase Requirement Of Contingent Convertible Senior Notes

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Convertible, Terms of Conversion Feature

'5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock Price Conversion Thresholds

'

'

'

'

$45.22

$59.71

$100.45

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Date of First Required Payment

'

'

'

'

14-May-16

14-Nov-17

14-Jun-19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Long_Term_Debt_Table_Phan

Debt - Long Term Debt Table (Phantom) (Details)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Senior Secured Term Loan Due 2017 [Member] | Unsecured Debt [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument Maturity Date	2-Dec-17	'
9.5% Senior Notes Due 2015 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	9.50%	'
Debt Instrument Maturity Date	15-Feb-15	'
3.25% Senior Notes due 2016 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	3.25%	3.25%
Debt Instrument Maturity Date	15-Mar-16	'
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	15-Jan-17	'
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	15-Aug-17	'
6.875% Senior Notes Due 2018 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%	6.88%
Debt Instrument Maturity Date	18-Aug-18	'
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	15-Dec-18	'
Floating Rate Senior Notes due 2019 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument Maturity Date	15-Apr-19	'
6.625% Senior Notes Due 2019 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%	'
Debt Instrument Maturity Date	15-Nov-19	'
6.625% Senior Notes Due 2020 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%	'
Debt Instrument Maturity Date	15-Aug-20	'
6.875% Senior Notes Due 2020 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%	'
Debt Instrument Maturity Date	15-Nov-20	'
5.375% Senior Notes due 2021 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	5.38%	5.38%
Debt Instrument Maturity Date	15-Jun-21	'
6.125% Senior Notes Due 2021 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	6.13%	'
Debt Instrument Maturity Date	15-Feb-21	'
4.875% Senior Notes due 2022 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	4.88%	'
Debt Instrument Maturity Date	15-Apr-22	'
5.75% Senior Notes due 2023 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	5.75%	5.75%
Debt Instrument Maturity Date	15-Mar-23	'
2.75% Contingent Convertible Senior Notes Due 2035 [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instruments Convertible Optional Repurchase Dates	'November 15, 2015, 2020, 2025, 2030	'
2.75% Contingent Convertible Senior Notes Due 2035 [Member] | Senior Notes [Member]	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Stated Percentage	2.75%	'
Debt Instrument Maturity Date	15-Nov-35	'
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	17-May-37	'
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	15-Dec-38	'

Debt_Term_Loans_Narrative_Deta

Debt - Term Loans Narrative (Details) (USD $)	9 Months Ended		3 Months Ended	9 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2014	Nov. 07, 2012	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Apr. 24, 2014
			Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Unsecured Debt [Member]	Senior Notes [Member]	Senior Notes [Member]
						Premium on Extinguishment of Term Loan Debt [Member]	Unamortized Discount on Extinguishment of Term Loan Debt [Member]	Unamortized Deferred Charges on Extinguishment of Term Loan Debt [Member]
Long-Term Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'
Credit Facility Commitment Period	'	'	'five-year	'	'	'	'	'	'	'
Unsecured Debt	'	'	'	'	$2,000,000,000	'	'	'	'	'
Proceeds from Issuance of Unsecured Debt	'	'	1,935,000,000	'	'	'	'	'	'	'
Long-term Debt, Gross	1,500,000,000	'	'	'	'	'	'	'	3,000,000,000	3,000,000,000
Gains (Losses) on Extinguishment of Debt	($61,000,000)	($37,000,000)	'	$90,000,000	'	$40,000,000	$30,000,000	$20,000,000	'	'

Debt_Senior_Notes_and_Continge

Debt - Senior Notes and Contingent Convertible Senior Notes Purchased Narrative (Details) (USD $)

9 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Apr. 24, 2014

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Minimum [Member]

Maximum [Member]

2.5% Contingent Convertible Senior Notes due 2037 [Member]

2.5% Contingent Convertible Senior Notes due 2037 [Member]

2.75% Contingent Convertible Senior Notes Due 2035 [Member]

2.75% Contingent Convertible Senior Notes Due 2035 [Member]

2.25% Contingent Convertible Senior Notes Due 2038 [Member]

2.25% Contingent Convertible Senior Notes Due 2038 [Member]

4.875% Senior Notes due 2022 [Member]

4.875% Senior Notes due 2022 [Member]

3.25% Senior Notes due 2016 [Member]

3.25% Senior Notes due 2016 [Member]

3.25% Senior Notes due 2016 [Member]

5.375% Senior Notes due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

7.625% Senior Notes Due 2013 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

6.875% Senior Notes Due 2018 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

9.5% Senior Notes Due 2015 [Member]

6.775% Senior Notes Due 2019 [Member]

6.775% Senior Notes Due 2019 [Member]

6.775% Senior Notes Due 2019 [Member]

Premium on Extinguishment of Senior Note Debt [Member]

Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Premium on Extinguishment of Senior Note Debt [Member]

Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]

Premium on Extinguishment of Senior Note Debt [Member]

Unamortized Discount on Extinguishment of Senior Note Debt [Member]

Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]

Unamortized Discount on Extinguishment of Senior Note Debt [Member]

Unamortized Deferred Charges on Extinguishment of Senior Note Debt [Member]

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Ownership Percentage

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

2.50%

'

2.75%

'

2.25%

'

4.88%

'

3.25%

'

3.25%

5.38%

'

5.38%

5.75%

'

5.75%

7.63%

6.88%

'

6.88%

'

'

9.50%

'

'

'

'

'

6.78%

'

'

Debt Instrument, Interest Rate, Effective Percentage

'

'

'

'

'

'

'

'

8.00%

'

6.86%

'

8.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

$2,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

1,500,000,000

3,000,000,000

'

3,000,000,000

'

'

50,000,000

75,000,000

1,168,000,000

1,168,000,000

396,000,000

396,000,000

347,000,000

347,000,000

1,500,000,000

0

500,000,000

500,000,000

500,000,000

700,000,000

700,000,000

700,000,000

1,100,000,000

1,100,000,000

1,100,000,000

247,000,000

0

97,000,000

'

'

'

0

1,265,000,000

'

'

'

'

'

'

'

Proceeds from issuance of senior notes, net of discount and offering costs

3,460,000,000

2,966,000,000

2,274,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchase Amount

'

'

405,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

221,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

217,000,000

97,000,000

'

377,000,000

'

'

1,265,000,000

'

1,454,000,000

'

'

'

1,300,000,000

'

'

Gain (Loss) on Repurchase of Debt Instrument

'

'

$37,000,000

'

$32,000,000

$5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$6,000,000

'

'

$5,000,000

$1,000,000

$99,000,000

'

'

$87,000,000

$9,000,000

$3,000,000

$33,000,000

$14,000,000

$19,000,000

Debt_Bank_Credit_Facilities_Na

Debt - Bank Credit Facilities Narrative (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2015
In Millions, unless otherwise specified			Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Line of Credit [Member]	Scenario, Forecast [Member]
			Corporate Revolving Bank Credit Facility [Member]	Corporate Revolving Bank Credit Facility [Member]	Corporate Revolving Bank Credit Facility [Member]	Corporate Revolving Bank Credit Facility [Member]	Corporate Revolving Bank Credit Facility [Member]	Corporate Revolving Bank Credit Facility [Member]	Line of Credit [Member]
			Minimum [Member]	Maximum [Member]	Union Bank N.A.	Union Bank N.A.	Union Bank N.A.	Union Bank N.A.	Corporate Revolving Bank Credit Facility [Member]
							Minimum [Member]	Maximum [Member]	Union Bank N.A.
Long-Term Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'
Borrowing capacity	'	'	'	'	$4,000	'	'	'	'
Debt Instrument Maturity Date	'	'	'	'	'	'	'	'	20-Dec-15
Interest Rate In Addition To Federal Funds Rate	'	'	'	'	0.50%	'	'	'	'
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimim	'	'	1.50%	'	'	'	0.50%	'	'
Debt Instrument, Interest Rage, Effective Percentage Rate Range, Maximum	'	'	'	2.25%	'	'	'	1.25%	'
Line of Credit Facility, Commitment Fee Percentage	'	'	'	'	0.50%	'	'	'	'
Long-term Debt, Gross	1,500	'	'	'	59	0	50	'	'
Letters of Credit Outstanding, Amount	'	'	'	'	15	'	'	'	'
Total long-term debt, net	$11,592	$12,886	'	'	$125	'	'	'	'

Debt_Debt_SpinOff_Debt_Transac

Debt Debt - Spin-Off Debt Transactions (Details) (USD $)	9 Months Ended	6 Months Ended			9 Months Ended			6 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Jun. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Apr. 24, 2014	Jun. 30, 2014
		Seven Seven Energy Inc. [Member]	Seven Seven Energy Inc. Revolving Bank Credit Facility [Member]	Secured Debt [Member]	Senior Notes [Member]	Senior Notes [Member]	Senior Notes [Member]	6.5% Senior Notes Due 2022 [Member]
			Seven Seven Energy Inc. [Member]	Seven Seven Energy Inc. [Member]				Senior Notes [Member]
								Seven Seven Energy Inc. [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]	'	'	'	'	'	'	'	'
Line of Credit Facility, Expiration Period	'	'	'5 years	'	'	'	'	'
Borrowing capacity	'	'	$275	'	'	'	'	'
Payments of Financing Costs	'	'	3	'	'	'	'	'
Long-term Debt, Gross	1,500	'	'	400	3,000	'	3,000	500
Debt Instrument, Term	'	'7 years	'	'	'	'	'	'
Proceeds from Issuance of Secured Debt	'	'	'	394	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	'	'	'	'	6.50%
Proceeds from issuance of senior notes, net of discount and offering costs	3,460	'	'	'	2,966	2,274	'	494
General Partner Distributions	'	'	'	'	'	'	'	$391

Debt_Debt_Fair_Value_of_Other_

Debt Debt - Fair Value of Other Financial Instruments (Table) (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Total long-term debt, net	$11,592	$12,886
Fair Value, Inputs, Level 1 [Member] | Reported Value Measurement [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Total long-term debt, net	11,523	10,501
Fair Value, Inputs, Level 1 [Member] | Estimate of Fair Value Measurement [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Total long-term debt, net	12,347	11,557
Fair Value, Inputs, Level 2 [Member] | Reported Value Measurement [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Total long-term debt, net	59	2,372
Fair Value, Inputs, Level 2 [Member] | Estimate of Fair Value Measurement [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Total long-term debt, net	$58	$2,369

Contingencies_Narrative_Detail

Contingencies - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'	'	'	'
Provision for legal contingencies	$100	$0	$100	$0

Commitments_Undiscounted_Gathe

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) (Gathering and Processing Equipment [Member], USD $)	Sep. 30, 2014
In Millions, unless otherwise specified
Gathering and Processing Equipment [Member]	'
Other Commitments [Line Items]	'
Other Commitment, Remainder of Fiscal Year	$616
Other Commitment, Due in Second Year	1,852
Other Commitment, Due in Third Year	1,933
Other Commitment, Due in Fourth Year	1,951
Other Commitment, Due in Fifth Year	1,748
Other Commitment, Due after Fifth Year	7,672
Other Commitment	$15,772

Commitments_Narrative_Details

Commitments - Narrative (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Jul. 20, 2011

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

In Millions, unless otherwise specified

Sundrop Fuels Inc [Member]

Sundrop Fuels Inc [Member]

Net Acreage Maintenance Commitment [Member]

Net Acreage Shortfall [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Pressure Pumping Crew Year One of Agreement [Member]

Pressure Pumping Crew Year Two of Agreement [Member]

Pressure Pumping Crew Year Three of Agreement [Member]

acre

Minimum [Member]

Maximum [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

Drilling Rig Leases [Member]

Pressure Pumping Leases [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Minimum [Member]

Maximum [Member]

Pressure Pumping Leases [Member]

Pressure Pumping Leases [Member]

Pressure Pumping Leases [Member]

Crew

Crew

Crew

Long-term Purchase Commitment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease Term

'

'

'

'

'

'

'

'3 months

'3 years

'

'3 months

'3 years

'

'

'

'

Operating Leases, Future Minimum Payment Due

'

'

'

'

'

'

$449

'

'

$356

'

'

$283

'

'

'

Cash Payment for Shortfall

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

Number Of Net Acres

'

'

'

'

'

20,800

'

'

'

'

'

'

'

'

'

'

Investments

254

477

155

155

'

'

'

'

'

'

'

'

'

'

'

'

Marketable Securities, Equity Securities

'

'

$25

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Crews

'

'

'

'

'

'

'

'

'

'

'

'

'

7

5

3

Year of Service Agreement

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'2 years

'3 years

Percent of Total

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

Other_Liabilities_Current_Tabl

Other Liabilities - Current Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Liabilities Disclosure [Abstract]	'	'
Revenues and royalties due others	$1,401	$1,409
Accrued natural gas, oil and NGL drilling and production costs	389	457
Joint interest prepayments received	382	464
Accrued compensation and benefits	250	320
Other accrued taxes	115	161
Accrued dividends	102	101
Other	496	599
Total other current liabilities	$3,135	$3,511

Other_Liabilities_LongTerm_Tab

Other Liabilities - Long-Term Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Long-Term Liabilities [Line Items]	'	'
Financing obligations	$30	$31
Other	236	237
Other Liabilities, Current	3,135	3,511
Total other long-term liabilities	687	984
Other Noncurrent Liabilities [Member]	'	'
Other Long-Term Liabilities [Line Items]	'	'
Unrecognized Tax Benefits	55	317
Noncontrolling Interest, Chesapeake Utica L L C [Member]	'	'
Other Long-Term Liabilities [Line Items]	'	'
Conveyance Obligation Noncurrent	227	250
Other Liabilities, Current	13	13
Total other long-term liabilities	240	263
Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]	'	'
Other Long-Term Liabilities [Line Items]	'	'
Conveyance Obligation Noncurrent	139	149
Other Liabilities, Current	21	12
Total other long-term liabilities	$160	$161

Equity_Common_Stock_Table_Deta

Equity - Common Stock Table (Details)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'
Common Stock, Shares, Issued Beginning of Period	666,192,371	666,468,000
Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures	-2,413,000	684,000
Stock option exercises	1,267,000	321,000
Common Stock, Shares, Issued End of Period	665,046,461	667,473,000

Equity_Convertible_Preferred_S

Equity - Convertible Preferred Stock Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding, beginning of period	7,251,515	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 [Line Items]	'	'	'	'
Shares outstanding, beginning of period	1,497,000	1,497,000	1,497,000	1,497,000
Shares outstanding, end of period	1,497,000	1,497,000	1,497,000	1,497,000
Preferred Stock, Liquidation Preference Per Share	$1,000,000	'	$1,000,000	'
5.75% Cumulative Convertible Preferred Stock Series A [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding, beginning of period	1,100,000	1,100,000	1,100,000	1,100,000
Shares outstanding, end of period	1,100,000	1,100,000	1,100,000	1,100,000
Preferred Stock, Liquidation Preference Per Share	$1,000,000	'	$1,000,000	'
4.50% Cumulative Convertible Preferred Stock [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding, beginning of period	2,559,000	2,559,000	2,559,000	2,559,000
Shares outstanding, end of period	2,559,000	2,559,000	2,559,000	2,559,000
Preferred Stock, Liquidation Preference Per Share	$100,000	'	$100,000	'
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding, beginning of period	2,096,000	2,096,000	2,096,000	2,096,000
Shares outstanding, end of period	2,096,000	2,096,000	2,096,000	2,096,000
Preferred Stock, Liquidation Preference Per Share	$100,000	'	$100,000	'

Equity_Equity_AOCI_Changes_Net

Equity Equity - AOCI Changes Net of Tax Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	($162)	'
Net current period other comprehensive income	3	1	11	13
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-151	'	-151	'
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	-162	-182
Other comprehensive income before reclassifications	'	'	3	-4
Amounts reclassified from accumulated other comprehensive income	3	0	8	17
Net current period other comprehensive income	'	'	11	13
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-151	-169	-151	-169
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	-167	-189
Other comprehensive income before reclassifications	'	'	3	2
Amounts reclassified from accumulated other comprehensive income	3	2	13	13
Net current period other comprehensive income	'	'	16	15
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-151	-174	-151	-174
Accumulated Other Comprehensive Income (Loss) [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	5	7
Other comprehensive income before reclassifications	'	'	0	-6
Amounts reclassified from accumulated other comprehensive income	'	'	-5	4
Net current period other comprehensive income	'	'	-5	-2
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	$0	$5	$0	$5

Equity_Equity_AOCI_Reclassific

Equity Equity - AOCI Reclassifications Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$3	$0	$8	$17
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	3	2	13	13
Accumulated Net Unrealized Investment Gain (Loss) [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	'	'	-5	4
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Impairment of Investment [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	'	'	0	6
Accumulated Net Unrealized Investment Gain (Loss) [Member] | Sale of Investment [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$0	($2)	($5)	($2)

Equity_Narrative_Details

Equity - Narrative (Details)	9 Months Ended
	Sep. 30, 2014
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five 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_Interest

Equity - Noncontrolling Interests Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

1 Months Ended

2 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 30, 2012

Mar. 30, 2012

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Mar. 31, 2012

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 30, 2012

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Oct. 31, 2011

Dec. 31, 2011

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2011

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Nov. 30, 2011

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Nov. 30, 2011

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Preferred Stock [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Cleveland Tonkawa L.L.C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Utica L L C [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Chesapeake Granite Wash Trust [Member]

Noncontrolling Interest, Wireless Seismic, Inc. [Member]

Noncontrolling Interest, Wireless Seismic, Inc. [Member]

Noncontrolling Interest, Wireless Seismic, Inc. [Member]

Noncontrolling Interest, Wireless Seismic, Inc. [Member]

Noncontrolling Interest, Wireless Seismic, Inc. [Member]

well

acre

acre

acre

Minimum, Six-Month Period in 2014 through 2016 [Member]

Minimum, Six-Month Period of June 30,2014 - December 31, 2014 [Member]

Minimum, Six-Month Period Through 2013 [Member]

Maximum [Member]

Wells, Future Wells [Member]

Wells, Percentage Increase in Future Net Wells [Member]

Wells, Drilled Wells [Member]

Wells, Qualified Wells [Member]

Wells, Qualified Wells [Member]

Preferred Stock [Member]

acre

acre

well

County

Minimum [Member]

Preferred Stock [Member]

well

acre

well

Minimum [Member]

Maximum [Member]

Maximum [Member]

Wells, Initial Number of Wells [Member]

Common Unit [Member]

Common Unit [Member]

Subordinated Units [Member]

well

well

well

well

well

Minimum [Member]

Minimum [Member]

well

well

acre

well

well

well

well

Noncontrolling Interest [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Net Acres

'

'

'

'

'

'

'

'

245,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

'

'

'

'

'

'

'

'

'

'

29,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Third-Party investors' contributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,250,000,000

'

'

'

'

'

'

'

'

'

'

'

$1,250,000,000

'

'

'

'

$1,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of preferred shares exchanged for cash

'

'

'

'

'

'

'

'

1,250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Wells, Net

'

'

'

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

13

74

'

'

'

'

'

1,500

'

'

'

1,300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Overriding Royalty Interest Percentage

'

'

'

'

'

'

'

'

'

3.75%

'

3.75%

'

'

3.75%

'

'

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Allocated To Overriding Royalty Interest

'

'

'

'

'

'

'

'

225,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends, Preferred Stock, Cash

'

'

'

'

'

'

'

'

1,025,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restricted cash and cash equivalents, current

38,000,000

'

38,000,000

'

75,000,000

'

37,000,000

'

'

38,000,000

'

38,000,000

'

38,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividend Rate, Percentage

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividends, Per Share, Cash Paid

'

'

'

'

'

'

'

'

'

'

'

$1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of excess cash allocated to preferred shares

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of excess cash allocated to common shares

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of excess cash allocated to preferred shares if drilling commitment not met

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Internal return on investment, multiplier

'

'

'

'

'

'

'

'

'

'

'

1.35

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of internal rate of return

'

'

'

'

'

'

'

'

'

'

'

9.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of increase in internal rate of return, in the event redemption does not occur

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Redemption Price Per Share

'

'

'

'

'

'

'

'

'

$1,200

'

$1,200

'

$1,245

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,189

'

$1,189

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Spacing for Wells Drilled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150

'

150

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of oil wells committed to drill net, minimum

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

25

12.5

37.5

'

'

'

867

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Net Wells Minimum Cumulative Total

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Of Excess Cash Distributed To Third Party Investors Percentage

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of increase in internal rate required by investors at redemption

'

'

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of additional increase in internal rate required by investors at redemption upon failed obligations

'

'

'

'

'

'

'

'

'

'

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of increase in leasehold in which commitment to drill is not met

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.00%

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acre Spacing

'

'

'

'

'

'

'

'

'

160

'

160

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stockholders' Equity Attributable to Noncontrolling Interest

1,311,000,000

'

1,311,000,000

'

2,145,000,000

'

'

'

'

1,015,000,000

'

1,015,000,000

'

1,015,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

0

'

'

807,000,000

'

'

291,000,000

'

291,000,000

'

314,000,000

'

'

'

'

'

'

'

'

6,000,000

'

6,000,000

'

9,000,000

Net income attributable to noncontrolling interests

30,000,000

38,000,000

110,000,000

127,000,000

'

'

'

'

'

19,000,000

19,000,000

56,000,000

56,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

6,000,000

19,000,000

43,000,000

60,000,000

'

'

'

'

6,000,000

2,000,000

14,000,000

14,000,000

'

'

'

'

'

'

'

'

'

1,000,000

1,000,000

3,000,000

3,000,000

'

Number of counties present in the leasehold land (Counties)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments for Repurchase of Preferred Stock and Preference Stock

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,254,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock Redemption Premium

447,000,000

0

447,000,000

69,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

447,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage Of Beneficial Interest Owned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

51.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Shares, Issued

665,046,461

667,473,000

665,046,461

667,473,000

666,192,371

666,468,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

'

'

Common stock, par value (usd per share)

$0.01

'

$0.01

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$19

'

'

'

'

'

'

'

'

'

'

'

'

Number of units included in beneficial interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,062,500

'

11,687,500

'

'

'

'

'

Common shares, outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46,750,000

'

46,750,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of proceeds from royalty interest conveyed to trust

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

90.00%

'

'

'

'

'

'

'

'

'

'

Number of producing wells

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69

'

69

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of development wells drilled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

95

80

'

'

'

'

'

118

'

'

'

'

'

'

'

'

Number Of Gross Acres

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45,400

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum amount recoverable by trust under lien

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$263,000,000

'

'

'

'

$51,000,000

$85,000,000

'

'

'

'

'

'

'

'

'

Percentage of incentive distributions received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of remaining cash available for distribution in excess of the incentive threshold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Ownership Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

52.00%

'

52.00%

'

'

Equity_Noncontrolling_Interest1

Equity - Noncontrolling Interests Distribution Table (Details) (Noncontrolling Interest, Chesapeake Granite Wash Trust [Member], USD $)	3 Months Ended
	31-May-14	Feb. 28, 2014	Nov. 30, 2013	31-May-13	Feb. 28, 2013	Nov. 30, 2012
Noncontrolling Interest [Line Items]	'	'	'	'	'	'
Distribution Made to Limited Partner, Distribution Date	29-Aug-14	30-May-14	3-Mar-14	29-Aug-13	31-May-13	1-Mar-13
Common Unit [Member]	'	'	'	'	'	'
Noncontrolling Interest [Line Items]	'	'	'	'	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.5796	0.6454	0.6624	0.69	0.69	0.67
Subordinated Units [Member]	'	'	'	'	'	'
Noncontrolling Interest [Line Items]	'	'	'	'	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0	0	0	0.1432	0.301	0.3772

ShareBased_Compensation_ShareB

Share-Based Compensation Share-Based Compensation - Restricted Stock Table (Details) (Restricted Stock [Member], USD $)	9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 30, 2014
Restricted Stock [Member]	'
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	13,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	4,882
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-4,557
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-3,279
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	10,446
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	$23.38
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$26.09
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$27.58
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$28.72
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	$21.14

ShareBased_Compensation_ShareB1

Share-Based Compensation Share-Based Compensation - Equity-Classified Valuation Table (Details) (Employee Stock Option [Member])	9 Months Ended
	Sep. 30, 2014
Employee Stock Option [Member]	'
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	'5 years 10 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	48.63%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.93%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.33%

ShareBased_Compensation_ShareB2

Share-Based Compensation Share-Based Compensation - Stock Option Activity Table (Details) (USD $)	0 Months Ended	9 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 30, 2013	Sep. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period Start	'	5,268
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures	'	994
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period	'	-1,309
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period	'	-28
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested Options Forfeited, Number of Shares	'	-313
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End	'	4,612
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	'	1,133
Weighted Average Exercise Price [Roll Forward]	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start	'	$19.28
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	'	$24.43
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	'	$18.75
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price	'	$18.97
Share-based Compensation Arrangements by Share-based Payment Award, Options, Forfeitures in Period, Weighted Average Exercise Price	'	$21.05
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End	'	$19.53
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	'	$18.71
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'	'6 years 9 months 10 days
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start	'	$41
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	'	11
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	'	5
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End	'	$17
Weighted Average Contract Life (in years) [Roll Forward]	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	'6 years 7 months 29 days	'7 years 7 months 17 days

ShareBased_Compensation_ShareB3

Share-Based Compensation Share-Based Compensation - Equity-Classified Compensation Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	$25	$35	$81	$123
General and Administrative Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	12	13	36	48
Oil and Gas Properties [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	6	12	22	45
Operating Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	5	5	13	17
Cost of Sales [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	2	2	5	5
Other Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	$0	$3	$5	$8

ShareBased_Compensation_ShareB4

Share-Based Compensation Share-Based Compensation - Liability Classified Valuation Table (Details) (Performance Shares [Member])	9 Months Ended
	Sep. 30, 2014
Performance Shares [Member]	'
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	41.37%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	0.76%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.36%

ShareBased_Compensation_ShareB5

Share-Based Compensation Share-Based Compensation - Performance Share Unit Breakout (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2012

Sep. 30, 2014

Dec. 31, 2012

Sep. 30, 2014

Dec. 31, 2012

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Payable 2015 [Member]

Payable 2015 [Member]

Payable 2016 [Member]

Payable 2016 [Member]

Payable 2017 [Member]

Payable 2017 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Year of 2014 [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

'

'

'

'

'

'

'

'

'

'

884,507

'

1,701,941

'

609,637

'

Allocated Share-based Compensation Expense

$25

$35

$81

$123

($13)

$25

$1

$41

$11

$2

'

'

'

'

'

'

Fair Value of Share Based Award

'

'

'

'

'

'

'

'

'

'

21

23

45

35

10

16

Share Based Award Liability, Current

'

'

'

'

'

'

'

'

'

'

$21

'

$42

'

$6

'

ShareBased_Compensation_ShareB6

Share-Based Compensation Share-Based Compensation - Liability-Classified Compensation Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	$25	$35	$81	$123
General and Administrative Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	12	13	36	48
Oil and Gas Properties [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	6	12	22	45
Operating Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	5	5	13	17
Cost of Sales [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	2	2	5	5
Performance Shares [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	-13	25	1	41
Performance Shares [Member] | General and Administrative Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	-12	18	-2	28
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	4	3	8
Performance Shares [Member] | Operating Expense [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	0	1	0	2
Performance Shares [Member] | Cost of Sales [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Allocated Share-based Compensation Expense	($1)	$2	$0	$3

ShareBased_Compensation_ShareB7

Share-Based Compensation Share-Based Compensation - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
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	$126	'	$126	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	160	'	160	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	'	'	'2 years 1 month 26 days	'
Restricted Stock [Member] | Minimum [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'	'	'3 years	'
Employee Stock Option [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	'	'	'1 year 11 months	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Method Used	'	'	'Black-Scholes option pricing model	'
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options	14	'	14	'
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	'
Management [Member] | Retention Based Stock Option Award [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	'	'	33.00%	'
Management [Member] | Incentive Based Stock Option Award [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] | Employee Stock Option [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Expiration Period	'	'	'10 years	'
Share-Based Comp Award One Year Anniversary [Member] | Management [Member] | Year of 2012 [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 Period	'	'	'1 year	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	'	'	'first	'
Share-Based Comp Award Two Year Anniversary [Member] | Management [Member] | Year of 2012 [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 Period	'	'	'2 years	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	'	'	'second	'
Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Year of 2012 [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 Period	'	'	'3 years	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights	'	'	'third	'
Share-Based Comp Award Three Year Anniversary [Member] | Management [Member] | Years of 2013 and 2014 [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
Stock Option Award Three Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [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	'
Stock Optioin Award Four Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [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	'
Stock option Award Five Year Anniversary [Member] | Management [Member] | Retention Based Stock Option Award [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	'
Long-Term Incentive Plan [Member] | Year of 2014 [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%	'	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2012 [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	'	'	0.00%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2012 [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	'	'	125.00%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2012 [Member] | Performance Shares and Operational Components [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	'	'	250.00%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2013 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2013 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2013 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2013 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2013 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2014 [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%	'
Long-Term Incentive Plan [Member] | Management [Member] | Year of 2014 [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%	'
Paid-In Capital [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Reduction in tax benefit from stock-based compensation	'	'	-1	-10
Paid-In Capital [Member] | Restricted Stock [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Reduction in tax benefit from stock-based compensation	4	0	1	12
Paid-In Capital [Member] | Employee Stock Option [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Reduction in tax benefit from stock-based compensation	$0	$2	$0	$2

Derivative_and_Hedging_Activit2

Derivative and Hedging Activities - Derivative Instruments Table (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
	Btu	Btu
Derivative [Line Items]	'	'
Fair Value	($167)	($551)
Natural Gas [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	-112	-237
Derivative, Nonmonetary Notional Amount, Energy Measure	801,000,000,000,000	1,009,000,000,000,000
Natural Gas [Member] | Swap [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	27	-23
Derivative, Nonmonetary Notional Amount, Energy Measure	224,000,000,000,000	448,000,000,000,000
Natural Gas [Member] | Three Way Collar [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	41	-7
Derivative, Nonmonetary Notional Amount, Energy Measure	278,000,000,000,000	288,000,000,000,000
Natural Gas [Member] | Collar [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	5	0
Derivative, Nonmonetary Notional Amount, Energy Measure	11,000,000,000,000	0
Natural Gas [Member] | Call Option [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	-183	-210
Derivative, Nonmonetary Notional Amount, Energy Measure	193,000,000,000,000	193,000,000,000,000
Natural Gas [Member] | Swaption [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	0	0
Derivative, Nonmonetary Notional Amount, Energy Measure	0	12,000,000,000,000
Natural Gas [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	-2	3
Derivative, Nonmonetary Notional Amount, Energy Measure	95,000,000,000,000	68,000,000,000,000
Crude Oil [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	-55	-314
Derivative, Nonmonetary Notional Amount, Volume	62,400,000	68,200,000
Crude Oil [Member] | Swap [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	113	-50
Derivative, Nonmonetary Notional Amount, Volume	19,600,000	25,300,000
Crude Oil [Member] | Three Way Collar [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	11	0
Derivative, Nonmonetary Notional Amount, Volume	4,400,000	0
Crude Oil [Member] | Call Option [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	-179	-265
Derivative, Nonmonetary Notional Amount, Volume	38,300,000	42,500,000
Crude Oil [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Fair Value	$0	$1
Derivative, Nonmonetary Notional Amount, Volume	100,000	400,000

Derivative_and_Hedging_Activit3

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	($249)	($649)
Derivative, Gain (Loss) on Derivative, Net	0	0
Short-term derivative assets	100	0
Long-term derivative assets	14	4
Derivative Liability, Current	-71	-208
Long-term derivative liabilities	-294	-445
Derivative Assets (Liabilities), at Fair Value, Net	-249	-649
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	-167	-553
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-167	-553
Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	-52	-98
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-52	-98
Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	-30	2
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-30	2
Other Current Assets [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	193	29
Derivative, Gain (Loss) on Derivative, Net	-93	-29
Short-term derivative assets	100	0
Other Noncurrent Assets [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	26	11
Derivative, Gain (Loss) on Derivative, Net	-12	-9
Long-term derivative assets	14	2
Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liability, gross liability	-155	-231
Derivative, Gain (Loss) on Derivative, Net	93	29
Derivative Liability, Current	-62	-202
Other Current Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liability, gross liability	-7	-6
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Liability, Current	-7	-6
Other Noncurrent Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liability, gross liability	-231	-362
Derivative, Gain (Loss) on Derivative, Net	12	9
Long-term derivative liabilities	-219	-353
Other Noncurrent Liabilities [Member] | Not Designated as Hedging Instrument [Member] | Interest Rate Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative liability, gross liability	-45	-92
Derivative, Gain (Loss) on Derivative, Net	0	0
Long-term derivative liabilities	-45	-92
Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Foreign Exchange Contract [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	'	2
Derivative liability, gross liability	-30	'
Derivative, Gain (Loss) on Derivative, Net	0	0
Long-term derivative assets	'	2
Long-term derivative liabilities	($30)	'

Derivative_and_Hedging_Activit4

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Natural gas, oil and NGL Sales	$2,341	$1,586	$5,812	$5,444
Natural Gas, Oil and NGL [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Natural gas, oil and NGL sales	1,777	1,839	5,842	5,303
Gains (losses) on undesignated natural gas and oil derivatives	569	-250	-5	162
Losses on terminated cash flow hedges	-5	-3	-25	-21
Natural gas, oil and NGL Sales	$2,341	$1,586	$5,812	$5,444

Derivative_and_Hedging_Activit5

Derivative and Hedging Activities - Interest Income and Interest Expense Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Trading Activity, Gains and Losses, Net [Line Items]	'	'	'	'
Total interest expense	$17	$40	$82	$164
Interest Expense [Member]	'	'	'	'
Trading Activity, Gains and Losses, Net [Line Items]	'	'	'	'
Interest expense on senior notes	170	180	534	560
Interest expense on term loans	0	29	36	87
Amortization of loan discount, issuance costs and other	9	21	44	70
Interest expense on credit facilities	6	8	22	30
Gains on terminated fair value hedges	0	0	-2	0
(Gains) losses on undesignated interest rate derivatives	2	-3	-48	51
Capitalized interest	-170	-195	-504	-634
Total interest expense	$17	$40	$82	$164

Derivative_and_Hedging_Activit6

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	'	'	'	($162)	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-151	'	-151	'	'	-162	'	'
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	'	'	'	'	'	-162	'	-182
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	-151	-169	-151	-169	'	-162	'	-182
Cash Flow Hedging [Member] | Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), before Tax [Roll Forward]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Before Tax Period Start	-238	-280	-238	-280	-243	-269	-286	-304
Net Change in Fair Value, Before Reclassifications, Before Tax	0	3	6	3	'	'	'	'
Derivative Instruments, Gains (Losses) Reclassified to Income, Before Tax	5	3	25	21	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Before Tax Period End	-238	-280	-238	-280	-243	-269	-286	-304
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]	'	'	'	'	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period Start	-154	-178	-167	-189	'	'	'	'
Net Change in Fair Value, Before Reclassification, Net of Tax	0	2	3	2	'	'	'	'
Derivative Instruments, Gains (Losses) Reclassified to Income, Net of Tax	3	2	13	13	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Net of Tax Period End	($151)	($174)	($151)	($174)	'	'	'	'

Derivative_and_Hedging_Activit7

Derivative and Hedging Activities Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value, Net	($249)	($649)
Fair Value, Measurements, Recurring [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value, Net	-251	-649
Fair Value, Measurements, Recurring [Member] | Commodity Contract [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Asset	219	40
Derivative Liability	-388	-593
Fair Value, Measurements, Recurring [Member] | Interest Rate Contract [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Interest Rate Derivative Liabilities, at Fair Value	-52	-98
Fair Value, Measurements, Recurring [Member] | Foreign Exchange Contract [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Foreign Currency Contracts, Liability, Fair Value Disclosure	-30	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	'	2
Fair Value, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | 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, Measurements, Recurring [Member] | 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]	'	'
Interest Rate Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | 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]	'	'
Foreign Currency Contracts, Liability, Fair Value Disclosure	0	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	'	0
Fair Value, Measurements, Recurring [Member] | 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	54	-171
Fair Value, Measurements, Recurring [Member] | 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	162	25
Derivative Liability	-26	-100
Fair Value, Measurements, Recurring [Member] | 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]	'	'
Interest Rate Derivative Liabilities, at Fair Value	-52	-98
Fair Value, Measurements, Recurring [Member] | 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]	'	'
Foreign Currency Contracts, Liability, Fair Value Disclosure	-30	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	'	2
Fair Value, Measurements, Recurring [Member] | 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	-305	-478
Fair Value, Measurements, Recurring [Member] | 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	57	15
Derivative Liability	-362	-493
Fair Value, Measurements, Recurring [Member] | 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]	'	'
Interest Rate Derivative Liabilities, at Fair Value	0	0
Fair Value, Measurements, Recurring [Member] | 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]	'	'
Foreign Currency Contracts, Liability, Fair Value Disclosure	0	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	'	$0

Derivative_and_Hedging_Activit8

Derivative and Hedging Activities Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012
Interest Rate Contract [Member]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	'	$0	'	'
Fair Value, Inputs, Level 3 [Member] | Natural Gas And Oil Sales [Member]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	60	327	'	'
Fair Value, Inputs, Level 3 [Member] | Interest Expense [Member]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)	0	0	'	'
Fair Value, Inputs, Level 3 [Member] | Commodity Contract [Member]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-305	-585	-478	-1,016
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	53	338	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	124	93	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	-4	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	'	0	'	'
Fair Value, Inputs, Level 3 [Member] | Interest Rate Contract [Member]	'	'	'	'
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	0	'	0	0
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	0	-1	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0	0	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0	'	'	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	'	$1	'	'

Derivative_and_Hedging_Activit9

Derivative and Hedging Activities Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Natural Gas [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-137
Natural Gas [Member] | Minimum [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	19.02%
Natural Gas [Member] | Maximum [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	52.92%
Natural Gas [Member] | Weighted Average [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	28.47%
Crude Oil [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-168
Crude Oil [Member] | Minimum [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	12.45%
Crude Oil [Member] | Maximum [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	20.94%
Crude Oil [Member] | Weighted Average [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Weighted Average Of Price Volatility Curve Percentage	15.96%

Recovered_Sheet2

Derivative and Hedging Activities - Narrative (Details)

9 Months Ended

1 Months Ended

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Apr. 24, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Dec. 31, 2006

Dec. 31, 2006

Dec. 31, 2006

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2014

Jun. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2012

USD ($)

USD ($)

Senior Notes [Member]

Senior Notes [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Swap [Member]

Swap [Member]

Basis Derivative [Member]

Price Risk Derivative [Member]

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

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

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

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

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

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

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

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

Minimum [Member]

Minimum [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

USD ($)

USD ($)

USD ($)

Credit Risk [Member]

Energy Related Derivative [Member]

USD ($)

USD ($)

Multi-Counterparty Hedging Facility [Member]

Multi-Counterparty Hedging Facility [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Multi-Counterparty Hedging Facility [Member]

USD ($)

USD ($)

USD ($)

USD ($)

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

Cash Flow Hedging [Member]

counterparty

counterparty

MMBoe

MMBoe

MMBoe

USD ($)

USD ($)

USD ($)

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

USD ($)

EUR (€)

USD ($)

EUR (€)

USD ($)

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate Derivatives, at Fair Value, Net

'

'

'

'

'

'

'

$52,000,000

$98,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Terminated Qualifying Interest Rate Derivative Transactions Duration

'6 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Amount of Hedged Item

'

'

'

'

'

'

'

1,450,000,000

2,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of counterparties in hedge facility

'

'

'

'

17

18

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Multi-counterparty hedging facility, committed to provide a trading capacity (in tcfe)

'

'

'

'

'

'

1,031,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Multi-counterparty hedge facility, committed to provide an aggregate mark-to-market capacity

'

'

'

'

16,500,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Multi-counterparty hedge facility, hedged total (in tcfe)

'

'

'

'

'

'

'

'

'

16,000,000

178,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural gas and oil proved reserves, the value of which must cover the fair value of the transactions outstanding under the facility, multiplier

'

'

'

'

1.3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.65

'

'

'

'

'

'

'

'

'

'

Deferred (Gain) Loss on Discontinuation of Fair Value Hedge

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3325

'

1.2631

'

1.3743

'

'

'

'

'

'

'

'

'

'

'

'

Semi Annual Interest Rate Swap Payments By Counterparty

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

'

344,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Short-term Debt, Refinanced, Description

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17,000,000

'

459,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dollar Equivalent Interest Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.49%

7.49%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative liability, gross liability

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative Asset, Fair Value, Gross Asset

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Euro-denominated debt in notes payable, adjusted value

1,500,000,000

'

3,000,000,000

3,000,000,000

'

'

'

'

'

'

'

435,000,000

473,000,000

344,000,000

'

'

435,000,000

'

'

50,000,000

'

'

'

'

'

'

'

'

'

'

'

Derivative Instruments, Gain (Loss) Reclassification from AOCI to Income, Estimated Net Amount to be Transferred

-147,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated other comprehensive loss

-151,000,000

-162,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-151,000,000

-162,000,000

-169,000,000

-182,000,000

-151,000,000

-154,000,000

-167,000,000

-174,000,000

-178,000,000

-189,000,000

Expected amount to be transferred of during the next 12 months

$26,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_T2

Natural Gas and Oil Property Transactions - VPP Transactions Table (Details) (USD $)

9 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Mar. 31, 2012

Mar. 31, 2012

Mar. 31, 2012

Mar. 31, 2012

Jun. 30, 2011

31-May-11

31-May-11

31-May-11

31-May-11

Sep. 30, 2010

Sep. 30, 2010

Sep. 30, 2010

Sep. 30, 2010

Mar. 31, 2010

Feb. 28, 2010

Feb. 28, 2010

Feb. 28, 2010

Feb. 28, 2010

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Sep. 30, 2008

Aug. 31, 2008

Aug. 31, 2008

Aug. 31, 2008

Aug. 31, 2008

Jun. 30, 2008

31-May-08

31-May-08

31-May-08

31-May-08

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

Mcf

MBbls

MBbls

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Business Combination, Separately Recognized Transactions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Proceeds from Volumetric Production Payment (VPP)

$5,661

'

'

'

$744

'

'

'

$853

'

'

'

'

$1,150

'

'

'

$180

'

'

'

'

$412

'

'

'

$600

'

'

'

'

$622

'

'

'

'

$1,100

'

'

'

Proved Developed Reserves (Volume)

'

1,149,000,000,000

5,500,000

14,000,000

'

87,000,000,000

3,000,000

9,200,000

'

'

138,000,000,000

1,700,000

4,800,000

'

390,000,000,000

0

0

'

'

44,000,000,000

300,000

0

'

95,000,000,000

500,000

0

'

'

93,000,000,000

0

0

'

'

94,000,000,000

0

0

'

208,000,000,000

0

0

Proved Developed Reserves (Energy)

1,266,000,000,000

'

'

'

160,000,000,000

'

'

'

'

177,000,000,000

'

'

'

390,000,000,000

'

'

'

'

46,000,000,000

'

'

'

98,000,000,000

'

'

'

'

93,000,000,000

'

'

'

'

94,000,000,000

'

'

'

208,000,000,000

'

'

'

Natural_Gas_and_Oil_Property_T3

Natural Gas and Oil Property Transactions - VPP Volumes Produced During Period Table (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
	Mcfe	Mcfe	Mcfe	Mcfe
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	35,400,000,000	41,900,000,000	112,000,000,000	130,000,000,000
Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	32,000,000,000	37,800,000,000	101,200,000,000	117,100,000,000
Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	166,200	209,500	523,600	667,100
NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	416,000	484,100	1,301,500	1,505,000
VPP 10 Anadarko Basin Granite Wash [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	5,000,000,000	6,300,000,000	15,800,000,000	19,800,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	2,600,000,000	3,300,000,000	8,100,000,000	10,300,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	98,000	131,000	310,000	426,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	314,500	371,900	989,600	1,158,600
VPP 9 Mid-Continent [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	4,700,000,000	5,200,000,000	14,400,000,000	16,000,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	3,800,000,000	4,200,000,000	11,700,000,000	12,900,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	46,100	52,300	142,600	162,700
VPP 9 Mid-Continent [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	101,500	112,200	311,900	346,400
VPP 8 Barnett Shale [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	14,800,000,000	16,700,000,000	45,700,000,000	52,000,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	14,800,000,000	16,700,000,000	45,700,000,000	52,000,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 8 Barnett Shale [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 6 East Texas and Texas Gulf Coast [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	1,100,000,000	1,200,000,000	3,400,000,000	3,600,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	1,100,000,000	1,200,000,000	3,300,000,000	3,600,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	6,000	6,000	18,000	18,000
VPP 6 East Texas and Texas Gulf Coast [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 5 South Texas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	1,200,000,000	1,900,000,000	4,700,000,000	5,800,000,000
VPP 5 South Texas [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	1,200,000,000	1,900,000,000	4,600,000,000	5,800,000,000
VPP 5 South Texas [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	4,200	6,700	16,500	18,900
VPP 5 South Texas [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	2,300,000,000	2,600,000,000	7,000,000,000	8,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	2,200,000,000	2,500,000,000	6,800,000,000	7,700,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	11,900	13,500	36,500	41,500
VPP 4 Anadarko and Arkoma Basins [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 3 Anadarko Basin [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	1,800,000,000	2,000,000,000	5,500,000,000	6,100,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	1,800,000,000	2,000,000,000	5,500,000,000	6,100,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 3 Anadarko Basin [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	1,100,000,000	2,500,000,000	5,100,000,000	7,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	1,100,000,000	2,500,000,000	5,100,000,000	7,800,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 1 Kentucky and West Virginia [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserve, Production (Energy)	3,400,000,000	3,500,000,000	10,400,000,000	10,900,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	3,400,000,000	3,500,000,000	10,400,000,000	10,900,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0
VPP 1 Kentucky and West Virginia [Member] | NGL [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves, Production	0	0	0	0

Natural_Gas_and_Oil_Property_T4

Natural Gas and Oil Property Transactions - VPP Volume Remaining to Be Delivered Table (Details)

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

31-May-11

Sep. 30, 2014

31-May-11

Sep. 30, 2014

31-May-11

Sep. 30, 2014

31-May-11

Sep. 30, 2014

Sep. 30, 2010

Sep. 30, 2014

Sep. 30, 2010

Sep. 30, 2014

Sep. 30, 2010

Sep. 30, 2014

Sep. 30, 2010

Sep. 30, 2014

Feb. 28, 2010

Sep. 30, 2014

Feb. 28, 2010

Sep. 30, 2014

Feb. 28, 2010

Sep. 30, 2014

Feb. 28, 2010

Sep. 30, 2014

Dec. 31, 2008

Sep. 30, 2014

Dec. 31, 2008

Sep. 30, 2014

Dec. 31, 2008

Sep. 30, 2014

Dec. 31, 2008

Sep. 30, 2014

Aug. 31, 2008

Sep. 30, 2014

Aug. 31, 2008

Sep. 30, 2014

Aug. 31, 2008

Sep. 30, 2014

Aug. 31, 2008

Sep. 30, 2014

31-May-08

Sep. 30, 2014

31-May-08

Sep. 30, 2014

31-May-08

Sep. 30, 2014

31-May-08

Sep. 30, 2014

Dec. 31, 2007

Sep. 30, 2014

Dec. 31, 2007

Sep. 30, 2014

Dec. 31, 2007

Sep. 30, 2014

Dec. 31, 2007

Sep. 30, 2014

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 8 Barnett Shale [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 6 East Texas and Texas Gulf Coast [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 4 Anadarko and Arkoma Basins [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 3 Anadarko Basin [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 2 Texas, Oklahoma and Kansas [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

VPP 1 Kentucky and West Virginia [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Reserve Volume Remaining [Member]

Natural Gas [Member]

Oil [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcfe

Reserve Volume Remaining [Member]

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL [Member]

NGL [Member]

Mcf

MBbls

MBbls

Mcfe

Reserve Volume Remaining [Member]

Reserve Volume Remaining [Member]

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcfe

Mcf

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

MBbls

Reserve Volume Remaining [Member]

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Oil and Gas Delivery Commitments and Contracts [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Term remaining (in months)

'

'

'

'

'

'

'

'

'89 months

'

'

'

'

'77 months

'

'

'

'

'

'

'

'11 months

'

'

'

'

'

'

'

'64 months

'

'

'

'

'

'

'

'27 months

'

'

'

'

'

'

'

'58 months

'

'

'

'

'

'

'

'55 months

'

'

'

'

'

'

'

'99 months

'

'

'

'

'

'

Proved Developed Reserves (Volume)

'

'

1,149,000,000,000

339,400,000,000

5,500,000

2,500,000

14,000,000

7,000,000

'

40,500,000,000

1,400,000

5,000,000

'

'

138,000,000,000

77,000,000,000

1,700,000

900,000

4,800,000

2,000,000

'

'

390,000,000,000

50,900,000,000

0

0

0

0

'

'

44,000,000,000

18,100,000,000

300,000

100,000

0

0

'

'

95,000,000,000

17,500,000,000

500,000

100,000

0

0

'

'

93,000,000,000

25,600,000,000

0

0

0

0

'

'

94,000,000,000

14,900,000,000

0

0

0

0

'

'

208,000,000,000

94,900,000,000

0

0

0

0

Proved Developed Reserves (Energy)

1,266,000,000,000

396,700,000,000

'

'

'

'

'

'

78,900,000,000

'

'

'

177,000,000,000

94,500,000,000

'

'

'

'

'

'

390,000,000,000

50,900,000,000

'

'

'

'

'

'

46,000,000,000

18,900,000,000

'

'

'

'

'

'

98,000,000,000

18,100,000,000

'

'

'

'

'

'

93,000,000,000

25,600,000,000

'

'

'

'

'

'

94,000,000,000

14,900,000,000

'

'

'

'

'

'

208,000,000,000

94,900,000,000

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_T5

Natural Gas and Oil Property Transactions - Narrative (Details) (USD $)

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Jul. 31, 2008

Jul. 31, 2008

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Minimum [Member]

Maximum [Member]

RKI Exploration & Production, LLC [Member]

RKI Exploration & Production, LLC [Member]

RKI Exploration & Production, LLC [Member]

Rice Drilling [Member]

Hilcorp Energy [Member]

Hilcorp Energy [Member]

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

JV Mississippian Lime [Member]

JV Mississippian Lime [Member]

JV Mississippian Lime [Member]

JV Utica [Member]

JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]

JV Marcellus, Barnett, Utica, Eagle Ford, Mid-Continent [Member]

Corporate VPP [Member]

acre

RKI Obligation [Member]

Chesapeake Obligation [Member]

Compressor [Member]

acre

Joint_Venture

acre

Payment Remaining [Member]

Closing adjustments between the effective date and the closing date transaction [Member]

acre

acre

Compressor

Resource_Plays

well

well

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Gross Acres

'

'

'

'

440,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Net Acres

'

'

'

'

'

203,000

137,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Wells, Gross

'

'

'

'

'

186

67

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Sold

'

'

20.00%

50.00%

'

48.00%

22.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds

'

'

'

'

'

'

$450,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from divestitures of proved and unproved properties

723,000,000

2,789,000,000

'

'

'

'

'

233,000,000

133,000,000

'

257,000,000

617,000,000

'

335,000,000

800,000,000

'

'

'

'

'

'

'

Equipment, Number of Units

'

'

'

'

'

'

'

'

'

61

'

'

'

'

'

'

'

'

'

'

'

'

Number of Joint Ventures

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

Number of Resource Plays

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Interest in Joint Venture

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000,000

'

949,000,000

71,000,000

90,000,000

'

24,000,000

48,000,000

'

Total Drilling Carries

9,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Oil And Gas Benefit From Drilling Carries

'

'

'

'

'

'

'

'

'

'

'

'

669,000,000

535,000,000

'

'

'

'

'

'

'

'

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

Gas and Oil Area, Developed, Net

'

'

'

'

'

'

'

'

'

'

'

'

850,000

'

850,000

'

'

'

'

'

'

'

Gain (Loss) on Disposition of Other Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

Drilling Carries Remaining

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$195,000,000

'

'

'

Percentage of Total Payment by Joint Venture Partner

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

'

'

'

Investments_Schedule_of_Invest

Investments - Schedule of Investments Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]	'	'
Investments	$254	$477
FTS International, Inc. [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Ownership Percentage	30.00%	30.00%
Investments	110	138
Sundrop Fuels Inc [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Ownership Percentage	56.00%	56.00%
Investments	132	135
Chaparral Energy, Inc. [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Ownership Percentage	0.00%	20.00%
Investments	0	143
Other Investment Companies [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Ownership Percentage	0.00%	0.00%
Investments	$12	$61

Investments_Narrative_Details

Investments - Narrative (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]	'	'	'
Investments	$254	'	$477
Proceeds from sales of investments	239	115	'
FTS International, Inc. [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Investments	110	'	138
Equity Investment Adjustments	37	'	'
Equity method accretion adjustments	9	'	'
Excess carrying value of investment over underlying equity in net assets	45	'	'
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]	'	'	'
Investments	132	'	135
Equity Investment Adjustments	17	'	'
Excess carrying value of investment over underlying equity in net assets	76	'	'
Interest Costs Capitalized	14	'	'
Chaparral Energy, Inc. [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Investments	0	'	143
Equity Method Investment, Net Sales Proceeds	209	'	'
Equity Method Investment, Realized Gain (Loss) on Disposal	73	'	'
Clean Energy Fuels Corp [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Cost Method Investments	'	100	'
Proceeds from Cost Method Investment	'	85	'
Other than Temporary Impairment Losses, Investments	'	15	'
Other Commitment	'	50	'
Other Investments [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Realized Gain (Loss) on Disposal	6	5	'
Proceeds from sales of investments	$30	$6	'

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Millions, unless otherwise specified					Variable Interest Entities, Primary Beneficiary [Member]	Variable Interest Entities, Primary Beneficiary [Member]	Corporate Ownership Requirement [Member]	Corporate Ownership Requirement [Member]	Corporate Ownership Requirement [Member]	Partner Ownership Requirement [Member]	Partner Ownership Requirement [Member]
							Mineral Acquisition Company I, L.P. [Member]	Mineral Acquisition Company I, L.P. [Member]	Mineral Acquisition Company I, L.P. [Member]	Mineral Acquisition Company I, L.P. [Member]	Mineral Acquisition Company I, L.P. [Member]
							Limited Partner [Member]	Minimum [Member]	Maximum [Member]	Limited Partner [Member]	Maximum [Member]
								Limited Partner [Member]	Limited Partner [Member]		Limited Partner [Member]
Variable Interest Entity [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Cash and cash equivalents	$90	$837	$987	$287	$1	$1	'	'	'	'	'
Proved natural gas and oil properties ($488 and $488 attributable to our VIE)	60,260	56,157	'	'	488	488	'	'	'	'	'
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment	38,349	37,161	'	'	220	168	'	'	'	'	'
Other Liabilities, Current	3,135	3,511	'	'	16	22	'	'	'	'	'
Percentage of acquisition	'	'	'	'	'	'	10.00%	'	'	90.00%	'
Other Commitment	'	'	'	'	'	'	'	'	25	'	225
Percentage of royalty minimum	'	'	'	'	'	'	'	7.00%	'	'	'
Percentage of royalty maximum	'	'	'	'	'	'	'	'	22.50%	'	'
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net	'	'	'	'	'	'	$9	'	'	'	'

Other_Property_and_Equipment_O

Other Property and Equipment Other Property and Equipment Net Gains (Losses) on Sales of Fixed Assets Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	($86)	($132)	($201)	($290)
Natural Gas Compressors [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	-75	0	-195	0
Gathering and Processing Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	-5	-132	8	-311
Exploration and Production Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	0	0	-7	1
Land and Building [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	-6	1	-5	24
Other Assets [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains on sales of fixed assets	$0	($1)	($2)	($4)

Other_Property_and_Equipment_O1

Other Property and Equipment Other Property and Equipment - Assets Held For Sale Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets Held for Sale	$101	$730
Land and Building [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets Held for Sale	101	405
Compressor [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets Held for Sale	0	285
Exploration and Production Equipment [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets Held for Sale	0	29
Natural Gas Processing Plant [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Assets Held for Sale	$0	$11

Other_Property_and_Equipment_N1

Other Property and Equipment - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains (losses) on sales of fixed assets	($86)	($132)	($201)	($290)
Reclassification from held for sale to held for use	116	'	116	'
Compressor [Member] | Hilcorp Energy [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Equipment, Number of Units	61	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	19	'	'	'
Net gains (losses) on sales of fixed assets	6	'	'	'
Compressor [Member] | Exterran Partners L.P. [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Equipment, Number of Units	162	'	499	'
Proceeds from Sale of Property, Plant, and Equipment	133	'	495	'
Net gains (losses) on sales of fixed assets	68	'	-161	'
Compressor [Member] | Access Midstream Partners, L.P. [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Equipment, Number of Units	'	'	102	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	159	'
Net gains (losses) on sales of fixed assets	'	'	-24	'
Gathering and Processing Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains (losses) on sales of fixed assets	-5	-132	8	-311
Gathering and Processing Equipment [Member] | SemGroup Corporation [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	306	'	'
Net gains (losses) on sales of fixed assets	141	'	'	'
Gathering and Processing Equipment [Member] | Granite Wash Midstream Gas Services, L.L.C. [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	'	252
Net gains (losses) on sales of fixed assets	'	'	'	-105
Gathering and Processing Equipment [Member] | Sale to Western Gas Partners, LP [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	'	134
Net gains (losses) on sales of fixed assets	'	'	'	-55
Exploration and Production Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	44	'
Net gains (losses) on sales of fixed assets	0	0	-7	1
Crude Oil Hauling Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net gains (losses) on sales of fixed assets	'	'	23	'
Drilling Rigs [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Equipment, Number of Units	'	8	14	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	14	'
Net gains (losses) on sales of fixed assets	'	'	($14)	'

Impairments_of_Fixed_Assets_an3

Impairments of Fixed Assets and Other - Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	$15	$85	$75	$343
Natural Gas Compressors [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	11	0	11	0
Gathering and Processing Equipment [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	0	21	10	22
Exploration and Production Equipment [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	0	24	23	27
Land and Building [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	4	8	9	247
Other Assets [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	$0	$32	$22	$47

Impairments_of_Fixed_Assets_an4

Impairments of Fixed Assets and Other - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	$15	$85	$75	$343
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	'	'	'	44
Net Acreage Shortfall [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Other Cost and Expense, Operating	'	'	22	'
Natural Gas Compressors [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	11	0	11	0
Gathering and Processing Equipment [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	0	21	10	22
Other Cost and Expense, Operating	'	26	'	'
Gathering and Processing Equipment [Member] | Marketing, Gathering And Compression [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	'	18	'	'
Drilling Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	'	24	15	'
Equipment, Number of Units	'	8	14	'
Leased Equipment Purchased	'	'	31	'
Payments to Acquire Property, Plant, and Equipment	'	'	140	'
Gain (Loss) on Contract Termination	'	'	8	'
Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	4	8	9	247
Land and Building [Member] | In the Oklahoma City Area [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	'	'	'	166
Land and Building [Member] | Assets Held-for-sale [Member] | In the Fort Worth Area [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	'	'	'	$31

Restructuring_and_Other_Termin1

Restructuring and Other Termination Benefits - Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Cash paid to purchase debt	'	'	$3,362	$2,141
Restructuring and other termination costs	-14	63	12	203
Ceo Aubrey K Mcclendon [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	'	'	'	67
Restructuring and other termination costs	-7	3	-5	67
Ceo Aubrey K Mcclendon [Member] | Other Restructuring and Termination Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	7
Ceo Aubrey K Mcclendon [Member] | Cash Salary and Bonus Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	11
Ceo Aubrey K Mcclendon [Member] | Claw-Back Bonus [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	11
Ceo Aubrey K Mcclendon [Member] | Acceleration of Restricted Stock Awards [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	22
Ceo Aubrey K Mcclendon [Member] | Acceleration of Performance Shares [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	-7	3	-5	16
Workforce Reduction Plan [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	'	31	'	'
Restructuring and other termination costs	0	31	0	31
Workforce Reduction Plan [Member] | Salary Expense [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	0	5	0	5
Workforce Reduction Plan [Member] | Acceleration of Stock-Based Compensation Awards [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	0	25	0	25
Workforce Reduction Plan [Member] | Other Restructuring and Termination Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	0	1	0	1
VSP Program [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	'	'	'	63
Restructuring and other termination costs	0	1	0	63
VSP Program [Member] | Other Restructuring and Termination Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	3
VSP Program [Member] | Cash Salary and Bonus Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	0	32
VSP Program [Member] | Acceleration of Restricted Stock Awards [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	1	0	28
Other, Including PSU's [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and other termination costs	-10	28	2	42
Seven Seven Energy Inc. [Member] | Spinoff [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Business Exit Costs	3	0	17	0
Adjustments to Additional Paid in Capital, Share-based Compensation and Exercise of Stock Options	0	0	5	0
Stock Granted, Value, Share-Based Compensation, Forfeited	0	0	-10	0
Cash paid to purchase debt	0	0	3	0
Restructuring and other termination costs	$3	$0	$15	$0

Restructuring_and_Other_Termin2

Restructuring and Other Termination Benefits - Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 30, 2012

Sep. 30, 2014

Sep. 30, 2013

Feb. 28, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Employee

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

VSP Program [Member]

VSP Program [Member]

VSP Program [Member]

VSP Program [Member]

VSP Program [Member]

VSP Program [Member]

Other, Including PSU's [Member]

Other, Including PSU's [Member]

Other, Including PSU's [Member]

Other, Including PSU's [Member]

One-time Termination Benefits [Member]

One-time Termination Benefits [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Seven Seven Energy Inc. [Member]

Employee

Employee

Spinoff [Member]

Spinoff [Member]

Spinoff [Member]

Spinoff [Member]

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and other termination costs

($14)

$63

$12

$203

($7)

$3

($5)

$67

$0

$31

$0

$31

'

$0

$1

'

$0

$63

($10)

$28

$2

$42

'

'

$3

$0

$15

$0

Restructuring and Related Cost, Number of Positions Eliminated

'

900

'

'

'

'

'

'

'

'

'

'

275

'

'

211

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and Related Cost, Incurred Cost

'

'

'

'

'

'

'

'

'

31

'

'

'

'

'

'

'

'

'

'

'

'

35

'

'

'

'

'

Payments for Restructuring

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

Severance Costs

'

'

'

'

'

'

'

$67

'

'

'

'

'

'

'

'

'

$63

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Fair_V1

Fair Value Measurements Fair Value Measurements - Assets and Liabilities Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Fair Value, Net Asset (Liability)	($1)	($2)
Other Current Assets [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Other Assets, Fair Value Disclosure	57	80
Other Current Liabilities [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Other Liabilities, Fair Value Disclosure	-58	-82
Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Fair Value, Net Asset (Liability)	-1	-2
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	57	80
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	-58	-82
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_Deta

Segment Information - Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$5,703	$4,867	$15,901	$12,965	'
Income (Loss) Before Income Taxes	1,129	387	2,246	1,561	'
Total Assets	40,518	'	40,518	'	41,782
Exploration and Production [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	2,341	1,586	5,812	5,444	'
Marketing, Gathering And Compression [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	3,362	3,032	9,543	6,871	'
Oilfield Services [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	245	516	636	'
Other Segments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	4	30	14	'
Reportable Subsegments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	5,703	4,867	15,901	12,965	'
Income (Loss) Before Income Taxes	1,129	387	2,246	1,561	'
Total Assets	40,518	'	40,518	'	41,782
Intersubsegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Operating Segments [Member] | Reportable Subsegments [Member] | Exploration and Production [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	2,341	1,586	5,812	5,444	'
Income (Loss) Before Income Taxes	987	430	2,089	654	'
Total Assets	34,876	'	34,876	'	35,341
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	5,512	5,034	16,289	12,553	'
Income (Loss) Before Income Taxes	113	128	325	395	'
Total Assets	2,420	'	2,420	'	2,430
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	551	1,060	1,677	'
Income (Loss) Before Income Taxes	0	-37	-16	-12	'
Total Assets	0	'	0	'	2,018
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	4	30	27	'
Income (Loss) Before Income Taxes	-63	-48	-24	808	'
Total Assets	4,357	'	4,357	'	5,750
Intersegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Intersegment Eliminations [Member] | Exploration and Production [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Intersegment Eliminations [Member] | Marketing, Gathering And Compression [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,150	-2,002	-6,746	-5,682	'
Intersegment Eliminations [Member] | Oilfield Services [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	-306	-544	-1,041	'
Intersegment Eliminations [Member] | Other Segments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	-13	'
Intersegment Eliminations [Member] | Reportable Subsegments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,150	-2,308	-7,290	-6,736	'
Income (Loss) Before Income Taxes	92	-86	-128	-284	'
Total Assets	-1,135	'	-1,135	'	-3,757
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$2,150	$2,308	$7,290	$6,736	'

Segment_Information_Narrative_

Segment Information - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
			Segment
Segment Reporting Information [Line Items]	'	'	'	'
Number of reportable segments	'	'	2	'
Revenues	$5,703	$4,867	$15,901	$12,965
Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	0	0	0	0
Marketing, Gathering And Compression [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	3,362	3,032	9,543	6,871
Marketing, Gathering And Compression [Member] | Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	-2,150	-2,002	-6,746	-5,682
Oilfield Services [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	0	245	516	636
Oilfield Services [Member] | Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	$0	($306)	($544)	($1,041)

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information - Balance Sheet Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$90	$837	$987	$287
Restricted cash	38	75	'	'
Other current assets	325	299	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	3,129	3,656	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	34,237	32,593	'	'
Other property and equipment, net	2,314	3,811	'	'
Property and equipment held for sale, net	101	730	'	'
Total Property and Equipment, Net	36,652	37,134	'	'
LONG-TERM ASSETS:	'	'	'	'
Other long-term assets	469	511	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
Total Assets	40,518	41,782	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	3,135	3,511	'	'
Intercompany payable, net	0	0	'	'
Current Liabilities	5,602	5,515	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	11,592	12,886	'	'
Deferred income tax liabilities	4,285	3,407	'	'
Other long-term liabilities	687	984	'	'
Total Long-Term Liabilities	17,285	18,127	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,320	15,995	'	'
Noncontrolling interests	1,311	2,145	'	'
Total Equity	17,631	18,140	18,348	'
TOTAL LIABILITIES AND EQUITY	40,518	41,782	'	'
Parent Company Member]	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	13	799	966	228
Restricted cash	0	0	'	'
Other current assets	73	103	'	'
Intercompany receivable, net	24,366	25,357	'	'
Total Current Assets	24,452	26,259	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil 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	105	111	'	'
Investments in subsidiaries and intercompany advances	3,805	2,361	'	'
Total Assets	28,362	28,731	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	247	300	'	'
Intercompany payable, net	0	0	'	'
Current Liabilities	247	300	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	11,533	11,831	'	'
Deferred income tax liabilities	132	209	'	'
Other long-term liabilities	130	396	'	'
Total Long-Term Liabilities	11,795	12,436	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,320	15,995	'	'
Noncontrolling interests	0	0	'	'
Total Equity	16,320	15,995	'	'
TOTAL LIABILITIES AND EQUITY	28,362	28,731	'	'
Guarantor Subsidiaries [Member]	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0	'	'
Other current assets	2,737	2,411	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	2,737	2,411	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	30,739	29,295	'	'
Other property and equipment, net	2,309	2,360	'	'
Property and equipment held for sale, net	101	701	'	'
Total Property and Equipment, Net	33,149	32,356	'	'
LONG-TERM ASSETS:	'	'	'	'
Other long-term assets	604	1,161	'	'
Investments in subsidiaries and intercompany advances	686	-262	'	'
Total Assets	37,176	35,666	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	5,308	5,227	'	'
Intercompany payable, net	23,807	24,775	'	'
Current Liabilities	29,115	30,002	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	59	0	'	'
Deferred income tax liabilities	3,305	2,281	'	'
Other long-term liabilities	892	1,022	'	'
Total Long-Term Liabilities	4,256	3,303	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	3,805	2,361	'	'
Noncontrolling interests	0	0	'	'
Total Equity	3,805	2,361	'	'
TOTAL LIABILITIES AND EQUITY	37,176	35,666	'	'
Non-Guarantor Subsidiaries [Member]	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	90	39	14	59
Restricted cash	38	82	'	'
Other current assets	191	578	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	319	699	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	2,999	3,113	'	'
Other property and equipment, net	5	1,452	'	'
Property and equipment held for sale, net	0	29	'	'
Total Property and Equipment, Net	3,004	4,594	'	'
LONG-TERM ASSETS:	'	'	'	'
Other long-term assets	28	96	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
Total Assets	3,351	5,389	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	68	344	'	'
Intercompany payable, net	703	558	'	'
Current Liabilities	771	902	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	1,055	'	'
Deferred income tax liabilities	713	830	'	'
Other long-term liabilities	386	788	'	'
Total Long-Term Liabilities	1,099	2,673	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	1,481	1,814	'	'
Noncontrolling interests	0	0	'	'
Total Equity	1,481	1,814	'	'
TOTAL LIABILITIES AND EQUITY	3,351	5,389	'	'
Eliminations [Member]	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	-13	-1	7	0
Restricted cash	0	-7	'	'
Other current assets	0	-348	'	'
Intercompany receivable, net	-24,366	-25,357	'	'
Total Current Assets	-24,379	-25,713	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	499	185	'	'
Other property and equipment, net	0	-1	'	'
Property and equipment held for sale, net	0	0	'	'
Total Property and Equipment, Net	499	184	'	'
LONG-TERM ASSETS:	'	'	'	'
Other long-term assets	0	-376	'	'
Investments in subsidiaries and intercompany advances	-4,491	-2,099	'	'
Total Assets	-28,371	-28,004	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	-21	-356	'	'
Intercompany payable, net	-24,510	-25,333	'	'
Current Liabilities	-24,531	-25,689	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	135	87	'	'
Other long-term liabilities	0	-372	'	'
Total Long-Term Liabilities	135	-285	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	-5,286	-4,175	'	'
Noncontrolling interests	1,311	2,145	'	'
Total Equity	-3,975	-2,030	'	'
TOTAL LIABILITIES AND EQUITY	-28,371	-28,004	'	'
Consolidated Entities [Member]	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Other current assets	3,001	2,744	'	'
LONG-TERM ASSETS:	'	'	'	'
Other long-term assets	737	992	'	'
CURRENT LIABILITIES:	'	'	'	'
Other Liabilities, Current	5,602	5,515	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Other long-term liabilities	$1,408	$1,834	'	'

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information -Statement Of Operations Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
REVENUES	'	'	'	'
Natural gas, oil and NGL	$2,341	$1,586	$5,812	$5,444
Marketing, gathering and compression	3,362	3,032	9,543	6,871
Oilfield services	0	249	546	650
Total Revenues	5,703	4,867	15,901	12,965
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	298	282	868	877
Production taxes	62	62	185	173
Marketing, gathering and compression	3,369	3,009	9,515	6,781
Oilfield services	0	211	431	543
General and administrative	60	120	229	336
Restructuring and other termination costs	-14	63	12	203
Provision for legal contingencies	100	0	100	0
Natural gas, oil and NGL depreciation, depletion and amortization	688	652	1,977	1,945
Depreciation and amortization of other assets	37	79	194	234
Impairment of natural gas and oil properties	0	0	0	0
Impairments of fixed assets and other	15	85	75	343
Net gains on sales of fixed assets	-86	-132	-201	-290
Total Operating Expenses	4,529	4,431	13,385	11,145
INCOME FROM OPERATIONS	1,174	436	2,516	1,820
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-17	-40	-82	-164
Losses on investments	-27	-22	-72	-36
Net gain (loss) on sales of investments	0	3	67	-7
Losses on purchases of debt	0	0	-195	-70
Other income (expense)	-1	10	12	18
Equity in net earnings of subsidiary	0	0	0	0
Total Other Expense	-45	-49	-270	-259
Income (Loss) Before Income Taxes	1,129	387	2,246	1,561
INCOME TAX EXPENSE (BENEFIT)	437	147	859	594
NET INCOME	692	240	1,387	967
Net income attributable to noncontrolling interests	-30	-38	-110	-127
Net income attributable to Chesapeake	662	202	1,277	840
Other Comprehensive Income (Loss), Net of Tax	3	1	11	13
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	665	203	1,288	853
Parent Company Member]	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services	0	0	0	0
Total Revenues	0	0	0	0
OPERATING EXPENSES	'	'	'	'
Natural gas, oil 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	0	0
General and administrative	0	0	0	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies	0	'	0	'
Natural gas, oil and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	0	0	0	0
Impairment of natural gas and oil properties	0	0	0	0
Impairments of fixed assets and other	0	0	0	0
Net gains on sales of fixed assets	0	0	0	0
Total Operating Expenses	0	0	0	0
INCOME FROM OPERATIONS	0	0	0	0
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-178	-207	-524	-703
Losses on investments	0	0	0	0
Net gain (loss) on sales of investments	'	0	0	0
Losses on purchases of debt	'	'	-195	-70
Other income (expense)	56	208	535	651
Equity in net earnings of subsidiary	737	201	1,391	916
Total Other Expense	615	202	1,207	794
Income (Loss) Before Income Taxes	615	202	1,207	794
INCOME TAX EXPENSE (BENEFIT)	-47	0	-70	-46
NET INCOME	662	202	1,277	840
Net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to Chesapeake	662	202	1,277	840
Other Comprehensive Income (Loss), Net of Tax	0	2	3	2
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	662	204	1,280	842
Guarantor Subsidiaries [Member]	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	2,085	1,340	5,100	4,903
Marketing, gathering and compression	3,361	3,031	9,539	6,861
Oilfield services	0	57	40	172
Total Revenues	5,446	4,428	14,679	11,936
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	284	262	818	833
Production taxes	59	60	177	167
Marketing, gathering and compression	3,368	3,009	9,512	6,776
Oilfield services	0	70	54	216
General and administrative	57	97	176	267
Restructuring and other termination costs	-14	63	9	200
Provision for legal contingencies	100	'	100	'
Natural gas, oil and NGL depreciation, depletion and amortization	599	549	1,750	1,729
Depreciation and amortization of other assets	37	45	116	142
Impairment of natural gas and oil properties	0	0	0	0
Impairments of fixed assets and other	15	31	52	282
Net gains on sales of fixed assets	-86	-133	-194	-291
Total Operating Expenses	4,419	4,053	12,570	10,321
INCOME FROM OPERATIONS	1,027	375	2,109	1,615
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-11	-27	-14	-70
Losses on investments	-27	-22	-69	-36
Net gain (loss) on sales of investments	'	3	67	-7
Losses on purchases of debt	'	'	0	0
Other income (expense)	120	44	12	120
Equity in net earnings of subsidiary	-2	-87	11	-241
Total Other Expense	80	-89	7	-234
Income (Loss) Before Income Taxes	1,107	286	2,116	1,381
INCOME TAX EXPENSE (BENEFIT)	429	142	804	617
NET INCOME	678	144	1,312	764
Net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to Chesapeake	678	144	1,312	764
Other Comprehensive Income (Loss), Net of Tax	3	1	8	12
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	681	145	1,320	776
Non-Guarantor Subsidiaries [Member]	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	256	245	715	532
Marketing, gathering and compression	1	1	4	10
Oilfield services	0	464	984	1,398
Total Revenues	257	710	1,703	1,940
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	14	20	50	44
Production taxes	3	2	8	6
Marketing, gathering and compression	1	0	3	5
Oilfield services	0	385	769	1,101
General and administrative	3	24	53	69
Restructuring and other termination costs	0	0	3	3
Provision for legal contingencies	0	'	0	'
Natural gas, oil and NGL depreciation, depletion and amortization	82	103	211	216
Depreciation and amortization of other assets	0	71	142	210
Impairment of natural gas and oil properties	104	99	202	260
Impairments of fixed assets and other	0	54	23	61
Net gains on sales of fixed assets	0	0	-7	0
Total Operating Expenses	207	758	1,457	1,975
INCOME FROM OPERATIONS	50	-48	246	-35
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	0	-21	-42	-63
Losses on investments	0	0	-5	0
Net gain (loss) on sales of investments	'	0	0	0
Losses on purchases of debt	'	'	0	0
Other income (expense)	-4	2	-2	7
Equity in net earnings of subsidiary	0	0	0	0
Total Other Expense	-4	-19	-49	-56
Income (Loss) Before Income Taxes	46	-67	197	-91
INCOME TAX EXPENSE (BENEFIT)	18	-25	76	-35
NET INCOME	28	-42	121	-56
Net income attributable to noncontrolling interests	0	0	0	0
Net income attributable to Chesapeake	28	-42	121	-56
Other Comprehensive Income (Loss), Net of Tax	0	-2	0	-1
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	28	-44	121	-57
Eliminations [Member]	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	0	1	-3	9
Marketing, gathering and compression	0	0	0	0
Oilfield services	0	-272	-478	-920
Total Revenues	0	-271	-481	-911
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	0	0	0	0
Production taxes	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services	0	-244	-392	-774
General and administrative	0	-1	0	0
Restructuring and other termination costs	0	0	0	0
Provision for legal contingencies	0	'	0	'
Natural gas, oil and NGL depreciation, depletion and amortization	7	0	16	0
Depreciation and amortization of other assets	0	-37	-64	-118
Impairment of natural gas and oil properties	-104	-99	-202	-260
Impairments of fixed assets and other	0	0	0	0
Net gains on sales of fixed assets	0	1	0	1
Total Operating Expenses	-97	-380	-642	-1,151
INCOME FROM OPERATIONS	97	109	161	240
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	172	215	498	672
Losses on investments	0	0	2	0
Net gain (loss) on sales of investments	'	0	0	0
Losses on purchases of debt	'	'	0	0
Other income (expense)	-173	-244	-533	-760
Equity in net earnings of subsidiary	-735	-114	-1,402	-675
Total Other Expense	-736	-143	-1,435	-763
Income (Loss) Before Income Taxes	-639	-34	-1,274	-523
INCOME TAX EXPENSE (BENEFIT)	37	30	49	58
NET INCOME	-676	-64	-1,323	-581
Net income attributable to noncontrolling interests	-30	-38	-110	-127
Net income attributable to Chesapeake	-706	-102	-1,433	-708
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	($706)	($102)	($1,433)	($708)

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information - Statements Of Cash Flows Table (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	$3,805	$3,586
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-3,185	-4,470
Acquisitions of proved and unproved properties	-1,023	-811
Proceeds from divestitures of proved and unproved properties	723	2,789
Additions to other property and equipment	-675	-639
Other	-4	4
Net Cash Used In Investing Activities	-2,938	-2,047
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	3,573	7,136
Payments on credit facilities borrowings	-3,896	-7,268
Proceeds from issuance of senior notes, net of discount and offering costs	3,460	'
Proceeds from issuance of oilfield services term loan, net of issuance costs	394	0
Cash paid to purchase debt	-3,362	-2,141
Proceeds from sales of noncontrolling interests	0	5
Other	-25	-71
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	-1,614	-839
Net increase (decrease) in cash and cash equivalents	-747	700
Cash and cash equivalents, beginning of period	837	287
Cash and cash equivalents, end of period	90	987
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	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	'
Cash paid to purchase debt	-3,362	-2,141
Proceeds from sales of noncontrolling interests	'	0
Other	-293	-374
Intercompany advances, net	-97	979
Net Cash Used In Financing Activities	-786	738
Net increase (decrease) in cash and cash equivalents	-786	738
Cash and cash equivalents, beginning of period	799	228
Cash and cash equivalents, end of period	13	966
Guarantor Subsidiaries [Member]	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	3,188	3,321
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-2,847	-3,826
Acquisitions of proved and unproved properties	-1,020	-402
Proceeds from divestitures of proved and unproved properties	726	2,736
Additions to other property and equipment	-423	-418
Other	1,143	67
Net Cash Used In Investing Activities	-2,421	-1,843
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	2,856	6,311
Payments on credit facilities borrowings	-2,797	-6,310
Proceeds from issuance of senior notes, net of discount and offering costs	0	0
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	'
Cash paid to purchase debt	0	0
Proceeds from sales of noncontrolling interests	'	5
Other	-1,300	-297
Intercompany advances, net	474	-1,187
Net Cash Used In Financing Activities	-767	-1,478
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	0	0
Non-Guarantor Subsidiaries [Member]	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	617	298
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-338	-644
Acquisitions of proved and unproved properties	-3	-409
Proceeds from divestitures of proved and unproved properties	-3	53
Additions to other property and equipment	-252	-221
Other	60	757
Net Cash Used In Investing Activities	-536	-464
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	717	825
Payments on credit facilities borrowings	-1,099	-958
Proceeds from issuance of senior notes, net of discount and offering costs	494	0
Proceeds from issuance of oilfield services term loan, net of issuance costs	394	'
Cash paid to purchase debt	0	0
Proceeds from sales of noncontrolling interests	'	0
Other	-159	46
Intercompany advances, net	-377	208
Net Cash Used In Financing Activities	-30	121
Net increase (decrease) in cash and cash equivalents	51	-45
Cash and cash equivalents, beginning of period	39	59
Cash and cash equivalents, end of period	90	14
Eliminations [Member]	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	0	-33
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	19	260
Net Cash Used In Investing Activities	19	260
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	0	0
Proceeds from issuance of oilfield services term loan, net of issuance costs	0	'
Cash paid to purchase debt	0	0
Proceeds from sales of noncontrolling interests	'	0
Other	-31	-220
Intercompany advances, net	0	0
Net Cash Used In Financing Activities	-31	-220
Net increase (decrease) in cash and cash equivalents	-12	7
Cash and cash equivalents, beginning of period	-1	0
Cash and cash equivalents, end of period	-13	7
Chesapeake Energy [Member]	'	'
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from issuance of senior notes, net of discount and offering costs	2,966	2,274
Consolidated Entities [Member]	'	'
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Other	1,222	1,084
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Other	($1,783)	($845)

Condensed_Consolidating_Financ5

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details) (Senior Notes [Member])	Sep. 30, 2014
Senior Notes [Member]	'
Condensed Financial Statements, Captions [Line Items]	'
Noncontrolling Interest, Ownership Percentage by Parent	100.00%

Subsequent_Events_Narrative_De

Subsequent Events - Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Oct. 15, 2014

Oct. 15, 2014

Oct. 14, 2014

Oct. 15, 2014

Oct. 15, 2014

Oct. 15, 2014

Oct. 15, 2014

Oct. 15, 2014

Oct. 15, 2014

Mcfe

Mcfe

Mcfe

Mcfe

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Southwestern [Member]

Boe

MMBoe

Natural Gas [Member]

Natural Gas Liquids [Member]

Condensate [Member]

North Western Virginia and Southern Pennsylvania [Member]

Marcellus and Utica Formations [Member]

Deposit Received [Member]

acre

Mcf

bbl

bbl

well

well

Subsequent Event [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds

'

'

'

'

'

'

$5,375

'

'

'

'

'

'

Proceeds from Sale of Productive Assets

'

'

'

'

'

'

'

'

'

'

'

'

$269

Number Of Net Acres

'

'

'

'

413,000

413,000

'

'

'

'

'

'

'

Number of Wells, Gross

'

'

'

'

'

'

'

'

'

'

1,500

435

'

Proved Developed and Undeveloped Reserve, Production (Energy)

35,400,000,000

41,900,000,000

112,000,000,000

130,000,000,000

56,000

221

'

'

'

'

'

'

'

Proved Developed and Undeveloped Reserves, Production

'

'

'

'

'

'

'

184,000

20,000

5,000

'

'

'

Percentage of Total Proved Reserves

'

'

'

'

'

'

'

8.00%

'

'

'

'

'