Expand Energy (EXE) 10-Q 7 May 14 2014 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	31-Mar-14	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
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	'	666,211,707

CONDENSED_CONSOLIDATED_BALANCE

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$1,004	$837
Restricted cash	75	75
Accounts receivable, net	2,593	2,222
Short-term derivative assets	2	0
Deferred income tax asset	243	223
Other current assets	358	299
Total Current Assets	4,275	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)	57,399	56,157
Unproved properties	11,672	12,013
Oilfield services equipment	2,239	2,192
Other property and equipment	3,429	3,203
Total Property and Equipment, at Cost	74,739	73,565
Less: accumulated depreciation, depletion and amortization (($190) and ($168) attributable to our VIE)	-37,844	-37,161
Property and equipment held for sale, net	627	730
Total Property and Equipment, Net	37,522	37,134
LONG-TERM ASSETS:	'	'
Investments	288	477
Long-term derivative assets	11	4
Other long-term assets	509	511
TOTAL ASSETS	42,605	41,782
CURRENT LIABILITIES:	'	'
Accounts payable	1,786	1,596
Short-term derivative liabilities ($6 and $5 attributable to our VIE)	417	208
Current maturities of long-term debt, net	316	0
Accrued interest	145	200
Other current liabilities ($19 and $22 attributable to our VIE)	3,294	3,511
Total Current Liabilities	5,958	5,515
LONG-TERM LIABILITIES:	'	'
Long-term debt, net	12,653	12,886
Deferred income tax liabilities	3,828	3,407
Long-term derivative liabilities	395	445
Asset retirement obligations	443	405
Other long-term liabilities	851	984
Total Long-Term Liabilities	18,170	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: 665,214,625 and 666,192,371 shares issued	7	7
Paid-in capital	12,459	12,446
Retained earnings	1,012	688
Accumulated other comprehensive loss	-153	-162
Less: treasury stock, at cost; 1,986,178 and 2,002,029 common shares	-46	-46
Total Chesapeake Stockholders’ Equity	16,341	15,995
Noncontrolling interests	2,136	2,145
Total Equity	18,477	18,140
TOTAL LIABILITIES AND EQUITY	$42,605	$41,782

CONDENSED_CONSOLIDATED_BALANCE1

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) (Parenthetical) (USD $)	Mar. 31, 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	665,214,625	666,192,371
Treasury stock, shares	1,986,178	2,002,029
Variable Interest Entities	'	'
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$1	$1
Proved natural gas and oil properties ($488 and $488 attributable to our VIE)	488	488
Less: accumulated depreciation, depletion and amortization (($190) and ($168) attributable to our VIE)	-190	-168
Short-term derivative liabilities ($6 and $5 attributable to our VIE)	6	5
Other current liabilities ($19 and $22 attributable to our VIE)	$19	$22

CONDENSED_CONSOLIDATED_STATEME

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
REVENUES:	'	'
Natural gas, oil and NGL	$1,766	$1,453
Marketing, gathering and compression	3,015	1,781
Oilfield services	265	190
Total Revenues	5,046	3,424
OPERATING EXPENSES:	'	'
Natural gas, oil and NGL production	288	307
Production taxes	50	53
Marketing, gathering and compression	2,980	1,745
Oilfield services	220	155
General and administrative	79	110
Restructuring and other termination costs	-7	133
Natural gas, oil and NGL depreciation, depletion and amortization	628	648
Depreciation and amortization of other assets	78	78
Impairments of fixed assets and other	20	27
Net gains on sales of fixed assets	-23	-49
Total Operating Expenses	4,313	3,207
INCOME FROM OPERATIONS	733	217
OTHER INCOME (EXPENSE):	'	'
Interest expense	-39	-21
Losses on investments	-21	-37
Net gain on sales of investments	67	0
Other income	6	6
Total Other Income (Expense)	13	-52
INCOME BEFORE INCOME TAXES	746	165
INCOME TAX EXPENSE	'	'
Current income taxes	3	1
Deferred income taxes	277	62
Total Income Tax Expense	280	63
NET INCOME	466	102
Net income attributable to noncontrolling interests	-41	-44
NET INCOME ATTRIBUTABLE TO CHESAPEAKE	425	58
Preferred stock dividends	-43	-43
Earnings allocated to participating securities	-8	0
NET INCOME AVAILABLE TO COMMON STOCKHOLDERS	$374	$15
EARNINGS PER COMMON SHARE:	'	'
Basic	$0.57	$0.02
Diluted	$0.54	$0.02
CASH DIVIDEND DECLARED PER COMMON SHARE	$0.09	$0
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):	'	'
Weighted Average Number of Shares Outstanding, Basic	658	651
Weighted Average Number of Shares Outstanding, Diluted	765	651

CONDENSED_CONSOLIDATED_STATEME1

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]	'	'
NET INCOME	$466	$102
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:	'	'
Unrealized gain (loss) on derivative instruments, net of income tax expense (benefit) of $1 million and ($1) million	3	-1
Reclassification of loss on settled derivative instruments, net of income tax expense of $7 million and $7 million	11	12
Unrealized loss on investments, net of income tax benefit of $0 and ($3) million	0	-5
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of ($3) million and $4 million	-5	6
Other Comprehensive Income	9	12
COMPREHENSIVE INCOME	475	114
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	-41	-44
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	$434	$70

CONDENSED_CONSOLIDATED_STATEME2

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Unrealized gain (loss) on derivative instruments, net of income tax expense (benefit) of $1 million and ($1) million	$1	($1)
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	7	7
Unrealized loss on investments, net of income tax benefit of $0 and ($3) million	0	-3
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	($3)	$4

CONDENSED_CONSOLIDATED_STATEME3

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME	$466	$102
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:	'	'
Depreciation, depletion and amortization	706	726
Deferred income tax expense	277	62
Derivative losses, net	363	143
Cash (payments) receipts on derivative settlements, net	-157	12
Stock-based compensation	20	32
Net gains on sales of fixed assets	-23	-49
Impairments of fixed assets and other	12	27
Losses on investments	21	29
Net gain on sales of investments	-67	0
Restructuring and other termination costs	-9	105
Other	5	-10
Changes in assets and liabilities	-323	-255
Net Cash Provided By Operating Activities	1,291	924
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-897	-1,579
Acquisitions of proved and unproved properties	-187	-280
Proceeds from divestitures of proved and unproved properties	49	190
Additions to other property and equipment	-437	-330
Proceeds from sales of other assets	239	201
Additions to investments	-3	-3
Proceeds from sales of investments	239	0
Decrease in restricted cash	0	55
Other	-2	1
Net Cash Used In Investing Activities	-999	-1,745
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	421	3,632
Payments on credit facilities borrowings	-362	-2,811
Cash paid for common stock dividends	-58	-58
Cash paid for preferred stock dividends	-43	-43
Cash paid on financing derivatives	-15	-11
Cash paid for prepayment of mortgage	0	-55
Distributions to noncontrolling interest owners	-53	-57
Other	-15	-30
Net Cash Provided By (Used In) Financing Activities	-125	567
Net increase (decrease) in cash and cash equivalents	167	-254
Cash and cash equivalents, beginning of period	837	287
Cash and cash equivalents, end of period	1,004	33
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'
Interest paid, net of capitalized interest	75	60
Income taxes paid, net of refunds received	0	0
SUPPLEMENTAL DISCLOSURE OF SIGNIFICANT NON-CASH INVESTING AND FINANCING ACTIVITIES:	'	'
Change in accrued drilling and completion costs	-168	-79
Change in accrued acquisitions of proved and unproved properties	7	-3
Change in accrued additions to other property and equipment	($2)	$11

CONDENSED_CONSOLIDATED_STATEME4

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited) (USD $)

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2014

Mar. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

In Millions, unless otherwise specified

Preferred Stock

Preferred Stock

Common Stock

Common Stock

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

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]

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Parent

Parent

Non-Controlling Interest

Non-Controlling Interest

Increase (Decrease) in Stockholders' Equity [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Chesapeake stockholders’ equity, beginning of period

$3,062

$3,062

$7

$7

'

'

$12,459

$12,446

$12,355

$12,293

'

'

$1,012

$688

$495

$437

'

'

($153)

($162)

($170)

($182)

'

'

($46)

($46)

($49)

($48)

$16,341

$15,700

'

'

Stock-based compensation

'

'

'

'

5

70

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax benefit (reduction in tax benefit) from stock-based compensation

'

'

'

'

3

-10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise of stock options

'

'

'

'

5

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income attributable to Chesapeake

'

'

'

'

'

'

'

'

'

'

425

58

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on common stock

'

'

'

'

'

'

'

'

'

'

-58

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on preferred stock

'

'

'

'

'

'

'

'

'

'

-43

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Hedging activity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

14

11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment activity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-5

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase of 10,156 and 160,145 shares for company benefit plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

-3

'

'

'

'

'

'

'

'

Release of 26,007 and 77,892 shares from company benefit plans

'

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'

'

'

'

'

'

'

'

'

0

2

'

'

'

'

'

'

'

'

Chesapeake stockholders’ equity, end of period

3,062

3,062

7

7

'

'

12,459

12,446

12,355

12,293

'

'

1,012

688

495

437

'

'

-153

-162

-170

-182

'

'

-46

-46

-49

-48

16,341

15,700

'

'

Net income attributable to noncontrolling interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

41

44

Distributions to noncontrolling interest owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($50)

($57)

CONDENSED_CONSOLIDATED_STATEME5

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Unaudited) (Parenthetical) (Treasury Stock - Common)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Treasury Stock - Common	'	'
Purchase of shares for company benefit plans, shares	10,156	160,145
Release of shares from company benefit plans, shares	26,007	77,892

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies (Note)	3 Months Ended
	Mar. 31, 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 are 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.
	This Form 10-Q relates to the three months ended March 31, 2014 (the “Current Quarter”) and the three months ended March 31, 2013 (the “Prior Quarter”). 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 are not necessarily indicative of the results to be expected for the full year.
	Risks and Uncertainties
	We recently conducted a company-wide review of our operations, assets and organizational structure to best position the Company to maximize shareholder value as we focus on our strategic priorities of financial discipline and profitable and efficient growth from captured resources. We intend to apply financial discipline through all aspects of our business, and we believe that the successful execution of this strategy will allow us to better balance capital expenditures with cash flow from operations as well as reduce financial leverage and complexity. While furthering our strategic priorities, certain actions that would reduce financial leverage and complexity could negatively impact our future results of operations and/or liquidity. We expect to incur various cash and noncash charges, including but not limited to impairments of fixed assets, lease termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity.

Earnings_Per_Share_Note

Earnings Per Share (Note)	3 Months Ended
	Mar. 31, 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 issuance of common shares for all potentially dilutive securities, provided the effect is not antidilutive. For the Current Quarter and the Prior Quarter, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted EPS. See Note 3 for further discussion of our contingent convertible senior notes.
	For the Prior Quarter, our cumulative convertible preferred stock and participating securities and associated adjustments to net income, consisting of 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 both the Current Quarter and the Prior Quarter. The following table sets forth the net income adjustments and shares of common stock related to our outstanding cumulative convertible preferred stock and participating securities in the Prior Quarter:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended March 31, 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
	Participating securities	$	—	—
	For the Current Quarter, all outstanding equity securities that were convertible into common stock were included in the calculation of diluted EPS. A reconciliation of basic EPS and diluted EPS for the Current Quarter is as follows:
		Net Income		Weighted	Per
		Available to		Average	Share
		Common		Shares	Amount
		Stockholders		(Denominator)
		(Numerator)
		(in millions, except per share data)
	Three Months Ended March 31, 2014:
	Basic EPS	$	374	658	$	0.57
	Effect of Dilutive Securities:
	Assumed conversion as of the beginning of the period
	of preferred shares outstanding during the period:
	Common shares assumed issued for 5.75%	21		56
	cumulative convertible preferred stock
	Common shares assumed issued for 5.75%	16		39
	cumulative convertible preferred stock (series A)
	Common shares assumed issued for 5.00%	3		5
	cumulative convertible preferred stock
	(series 2005B)
	Common shares assumed issued for 4.50%	3		6
	cumulative convertible preferred stock
	Outstanding stock options	—		1
	Diluted EPS	$	417	765	$	0.54

Debt_Note

Debt (Note)	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Debt Disclosure [Text Block]	'
	Debt
	Our long-term debt consisted of the following as of March 31, 2014 and December 31, 2013:
			March 31,				December 31,
			2014				2013
			($ in millions)
	Term loan due 2017(a)		$	2,000			$	2,000
	9.5% senior notes due 2015(b)		1,265				1,265
	3.25% senior notes due 2016		500				500
	6.25% euro-denominated senior notes due 2017(c)		473				473
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018(d)		97				97
	7.25% senior notes due 2018		669				669
	6.625% senior notes due 2019(e)		650				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
	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		—				—
	Oilfield services revolving bank credit facility		464				405
	Discount on senior notes and term loan(g)		(333		)		(357		)
	Interest rate derivatives(h)		13				13
	Total debt, net		12,969				12,886
	Less current maturities of long-term debt, net(b)		(316		)		—
	Total long-term debt, net		$	12,653			$	12,886
	___________________________________________
	(a)	We repaid the borrowings outstanding under the term loan due 2017 on April 24, 2014 with a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes issued on April 24, 2014. See Note 19 for further discussion of refinancing transactions subsequent to March 31, 2014.
	(b)	On April 10, 2014, we commenced a tender offer for the 9.5% Senior Notes due 2015 concurrently with an offering of senior notes. On April 24, 2014, we purchased approximately $946 million aggregate principal amount of notes that were tendered by the early tender date. The tender offer will expire on May 7, 2014, unless extended. See Note 19 for further discussion of refinancing transactions subsequent to March 31, 2014. The remaining $319 million in aggregate principal amount not tendered by the early tender date and the associated $3 million of discount are reflected as a current liability on our March 31, 2014 condensed consolidated balance sheet.
	(c)	The principal amount shown is based on the exchange rate of $1.3769 to €1.00 and $1.3743 to €1.00 as of March 31, 2014 and December 31, 2013, respectively. See Note 8 for information on our related foreign currency derivatives.
	(d)	On April 10, 2014, we called the 6.875% Senior Notes due 2018 for redemption on May 12, 2014. See Note 19 for discussion of refinancing transactions subsequent to March 31, 2014.
	(e)	Issuers are Chesapeake Oilfield Operating, L.L.C. (COO), an indirect wholly owned subsidiary of the Company, and Chesapeake Oilfield Finance, Inc. (COF), a wholly owned subsidiary of COO formed solely to facilitate the offering of the 6.625% Senior Notes due 2019. COF is nominally capitalized and has no operations or revenues. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes.
	(f)	The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances 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. In the first quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the second quarter of 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. Under certain conditions, we will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years. 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. The optional repurchase dates, the common stock price conversion threshold amounts 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		Repurchase Dates		Common Stock				Contingent Interest
	Convertible				Price Conversion				First Payable
	Senior  Notes				Thresholds				(if applicable)
	2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	48.09			May 14, 2016
	2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	63.62			November 14, 2017
	2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	106.75			June 14, 2019
	(g)	Discount as of March 31, 2014 and December 31, 2013 included $284 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 $30 million and $33 million as of March 31, 2014 and December 31, 2013, respectively, associated with our term loan discussed further below.
	(h)	See Note 8 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. On April 24, 2014, the Company used a portion of the net proceeds from its offering of $3.0 billion in aggregate principal amount of senior notes to repay the borrowings under, and terminate, the term loan. See Note 19 for further discussion related to the refinancing transactions subsequent to March 31, 2014.
	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 17 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, depending on the indenture.
	We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.
	In March 2013, the Company brought suit in the U.S. District Court for the Southern District of New York (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 on March 15, 2013 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 March 15, 2013 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 in late April and on May 8, 2013 ruled in the Company’s favor. On May 11, 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 February 2015. See Note 19 for discussion of senior notes refinancing transactions subsequent to March 31, 2014.
	COO Senior Notes
	The COO senior notes are the unsecured senior obligations of COO and rank equally in right of payment with all of COO’s other existing and future senior unsecured indebtedness and rank senior in right of payment to all of its future subordinated indebtedness. The COO senior notes are jointly and severally, fully and unconditionally guaranteed by all of COO’s wholly owned subsidiaries, other than de minimis subsidiaries. The notes may be redeemed by COO at any time at specified make-whole or redemption prices and, prior to November 15, 2014, up to 35% of the aggregate principal amount may be redeemed in connection with certain equity offerings. Holders of the COO notes have the right to require COO to repurchase their notes upon a change of control on the terms set forth in the indenture, and COO must offer to repurchase the notes upon certain asset sales. The COO senior notes are subject to covenants that may, among other things, limit the ability of COO and its subsidiaries to make restricted payments, incur indebtedness, issue preferred stock, create liens, and consolidate, merge or transfer assets. The COO senior notes have cross default provisions that apply to other indebtedness COO or any of its guarantor subsidiaries may have from time to time with an outstanding principal amount of $50 million or more.
	Bank Credit Facilities
	During the Current Quarter, we had the following two revolving bank credit facilities as sources of liquidity:
			Corporate				Oilfield Services
			Credit Facility(a)				Credit Facility(b)
			($ in millions)
	Facility structure		Senior secured				Senior secured
			revolving				revolving
	Maturity date		December 2015				November 2016
	Borrowing capacity		$	4,000			$	500
	Amount outstanding as of March 31, 2014		$	—			$	464
Letters of credit outstanding as of March 31, 2014		$	23			$	—
___________________________________________
(a)	Co-borrowers are Chesapeake Exploration, L.L.C., Chesapeake Appalachia, L.L.C. and Chesapeake Louisiana, L.P.
(b)	Borrower is COO.
Although the applicable interest rates under our corporate credit facility fluctuate based on our long-term senior unsecured credit ratings, our credit facilities do not contain provisions which would trigger an acceleration of amounts due under the respective facilities or a requirement to post additional collateral in the event of a downgrade of our credit ratings.
Corporate Credit Facility. Our $4.0 billion syndicated revolving bank credit facility is used for general corporate purposes. 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, it may be payable at more frequent intervals.
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 March 31, 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, equipment master lease agreements, term loan 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.
Oilfield Services Credit Facility. Our $500 million syndicated oilfield services revolving bank credit facility is used to fund capital expenditures and for general corporate purposes associated with our oilfield services operations. Borrowings under the oilfield services credit facility are secured by all of the assets of the wholly owned subsidiaries of COO, itself an indirect wholly owned subsidiary of Chesapeake. The facility has initial commitments of $500 million and may be expanded to $900 million at COO’s option, subject to additional bank participation. Borrowings under the credit facility are secured by all of the equity interests and assets of COO and its wholly owned subsidiaries (the restricted subsidiaries for this facility, which are unrestricted subsidiaries under Chesapeake’s senior notes, contingent convertible senior notes, term loan and corporate revolving bank credit facility), and bear interest at our option at either (i) the greater of the reference rate of Bank of America, N.A., the federal funds effective rate plus 0.50%, or one-month LIBOR plus 1.00%, all of which are subject to a margin that varies from 1.00% to 1.75% per annum, or (ii) the Eurodollar rate, which is based on LIBOR plus a margin that varies from 2.00% to 2.75% per annum. The unused portion of the credit facility is subject to a commitment fee that varies from 0.375% to 0.50% per annum. Both margins and commitment fees are determined according to the most recent leverage ratio described below. Interest is payable quarterly or, if LIBOR applies, it may be payable at more frequent intervals.
The oilfield services credit facility agreement contains various covenants and restrictive provisions which limit the ability of COO and its restricted subsidiaries to enter into asset sales, incur additional indebtedness, make investments or loans and create liens. The agreement requires maintenance of a leverage ratio based on the ratio of lease-adjusted indebtedness to earnings before interest, taxes, depreciation, amortization and rent (EBITDAR), a senior secured leverage ratio based on the ratio of secured indebtedness to EBITDA and a fixed charge coverage ratio based on the ratio of EBITDAR to lease-adjusted interest expense, in each case as defined in the agreement. COO was in compliance with all covenants under the agreement as of March 31, 2014. If COO or its restricted subsidiaries should fail to perform their obligations under the 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 COO senior note indenture, which could in turn result in the acceleration of the COO senior note indebtedness. The oilfield services credit facility agreement also has cross default provisions that apply to other indebtedness COO and its restricted subsidiaries may have from time to time with an outstanding principal amount in excess of $15 million.
Fair Value of Other Financial Instruments
We estimate the fair value of our exchange-traded debt using quoted market prices (Level 1). The fair value of all other debt, which consists of our credit facilities and our term loan, is estimated using our credit default swap rate (Level 2). Fair value is compared to the carrying value, excluding the impact of interest rate derivatives, in the table below.
		31-Mar-14							31-Dec-13
		Carrying				Estimated			Carrying		Estimated
		Amount				Fair Value			Amount		Fair Value
						($ in millions)
Long-term debt (Level 1)		$	10,522			$	11,639		$	10,501	$	11,557
Long-term debt (Level 2)		$	2,434			$	2,432		$	2,372	$	2,369

Contingencies_and_Commitments_

Contingencies and Commitments (Note)	3 Months Ended
	Mar. 31, 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. 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. The appeal has been fully briefed and oral argument is scheduled for May 14, 2014. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with this matter.
	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 its 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 resolution of the Tenth Circuit appeal.
	2012 Securities and Shareholder Litigation. A putative class action was filed in the U.S. District Court for the Western District of Oklahoma on April 26, 2012 against the Company and its former Chief Executive Officer (CEO), Aubrey K. McClendon. On July 20, 2012, the court appointed a lead plaintiff, which filed an amended complaint on October 19, 2012 against the Company, Mr. McClendon and certain other officers. The amended complaint asserted claims under Sections 10(b) (and Rule 10b-5 promulgated thereunder) and 20(a) of the Securities Exchange Act of 1934 based on alleged misrepresentations regarding the Company’s asset monetization strategy, including liabilities associated with its volumetric production payment (VPP) transactions, as well as Mr. McClendon’s personal loans and the Company’s internal controls. On December 6, 2012, the Company and other defendants filed a motion to dismiss the action. On April 10, 2013, the Court granted the motion, and on April 16, 2013, entered judgment against the plaintiff and dismissed the complaint with prejudice. The plaintiff filed a notice of appeal on June 14, 2013 in the U.S. Court of Appeals for the Tenth Circuit. Briefing on the appeal was complete on August 2, 2013, and on November 18, 2013 argument was heard. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with this matter.
	A related federal consolidated derivative action and an Oklahoma state court derivative action are stayed pursuant to the parties' stipulation pending resolution of the appeal in the federal securities class action.
	On May 8, 2012, a derivative action was filed in the District Court of Oklahoma County, Oklahoma against the Company's directors alleging, among other things, 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.
	2014 Shareholder Litigation. 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.
	Regulatory Proceedings. On May 2, 2012, Chesapeake and Mr. McClendon received notice from the U.S. Securities and Exchange Commission that its Fort Worth Regional Office had commenced an informal inquiry into, among other things, certain of the matters alleged in the foregoing 2012 securities and shareholder lawsuits. On December 21, 2012, the SEC’s Fort Worth Regional Office advised Chesapeake that its inquiry was continuing as an investigation. The Company provided information and testimony to the SEC pursuant to subpoenas and otherwise in connection with this matter and is also responding to related inquiries from other governmental and regulatory agencies and self-regulatory organizations. On April 8, 2014, the SEC’s Fort Worth Regional Office advised Chesapeake that it had concluded its investigation and, based on the information it had as of that date, did not intend to recommend an enforcement action by the SEC.
	The Company has received, from the Antitrust Division of the U.S. Department of Justice (DOJ) and certain state governmental agencies, subpoenas and demands for documents, information and testimony in connection with investigations into possible violations of federal and state laws relating to our purchase and lease of oil and gas rights in various states. Chesapeake has engaged in discussions with the DOJ and state agencies 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.
	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 cases in various courts, has settled others and believes that it has substantial defenses to the claims made in those pending at the trial court and on appeal. Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits allege 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 is defending against certain pending claims, has resolved a number of claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits.
	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 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 Proceedings
	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 addressing 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.
	On December 19, 2013, our subsidiary Chesapeake Appalachia, LLC (CALLC) entered into a consent decree with the U.S. Environmental Protection Agency (EPA), the U.S. Department of Justice (DOJ) and the West Virginia Department of Environmental Protection (WVDEP) to resolve alleged violations of the Clean Water Act (CWA) and the West Virginia Water Pollution Control Act at 27 sites in West Virginia. In a complaint filed against CALLC the same day in the U.S. District Court for the Northern District of West Virginia, the EPA and WVDEP alleged that CALLC impounded streams and discharged sand, dirt, rocks and other fill material into streams and wetlands without a federal permit in order to construct well pads, impoundments, road crossings and other facilities related to natural gas extraction. The consent decree was approved and entered by the court on March 11, 2014.
	In accordance with the consent decree, CALLC paid a civil penalty of $3.2 million, which was divided evenly between the U.S. and the state of West Virginia. The consent decree settlement also requires that CALLC restore the affected wetlands and streams in accordance with an agreed plan, monitor the restored sites for up to 10 years to assure the success of the restoration, and implement a comprehensive compliance program to ensure future compliance with the CWA and applicable West Virginia law. To offset the impacts to sites, CALLC is required by the consent decree to perform compensatory mitigation, which will likely involve purchasing credits from a wetland mitigation bank located in a local watershed. We believe that compliance with the consent decree will not have a material adverse impact on our business.
	In a related case, in December 2012, CALLC pled guilty to three misdemeanor violations of the CWA for unauthorized discharge at one of the sites subject to the consent decree of crushed stone and gravel into a local stream to create a roadway to improve access to a drilling site. CALLC paid a $600,000 penalty and is subject to a two-year probation ending in December 2014. CALLC has fully restored the site, and we believe that CALLC is in compliance with the terms of probation. By operation of law, a CWA conviction triggers “disqualification”, by which the disqualified entity is prohibited from receiving federal contracts or benefits until the EPA certifies that the conditions giving rise to the conviction have been corrected. Disqualification of CALLC has not had, and we do not expect it to have, a material adverse impact on our business.
	Commitments
	Rig Leases
	As of March 31, 2014, we leased 25 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $20 million. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. Under the leases, we can exercise an early purchase option or we can purchase the rigs at the expiration of the lease for the fair market value at the time. In addition, in most cases, we have the option to renew a lease for negotiated new terms at the expiration of the lease. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. During the Current Quarter, we purchased 20 leased rigs from various lessors for an aggregate purchase price of approximately $77 million and paid approximately $8 million in lease termination costs. Through these transactions, we lowered our minimum aggregate undiscounted future rig lease payments by approximately $43 million.
	Compressor Leases
	As of March 31, 2014, we leased 346 compressors under master lease agreements with an aggregate undiscounted future lease commitment of $63 million. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. Under the leases, we can exercise an early purchase option or we can purchase the compressors at the expiration of the lease for the fair market value at the time. In addition, in most cases we have the option to renew a lease for negotiated new terms at the expiration of the lease. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. During the Current Quarter, we purchased 1,435 leased compressor units from various lessors for an aggregate purchase price of approximately $271 million, lowering our minimum aggregate undiscounted future compressor lease payments by approximately $196 million.
	Gathering, Processing and Transportation Agreements
	We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying condensed consolidated balance sheets; however, they are reflected as adjustments to natural gas, oil and NGL sales prices used in our proved reserves estimates.
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners or credits for third-party volumes, are presented below.
		March 31, 2014
		($ in millions)
	2014	$	1,546
	2015	1,830
	2016	1,915
	2017	1,948
	2018	1,749
	2019 - 2099	7,746
	Total	$	16,734
	Drilling Contracts
	Chesapeake has contracts with various drilling contractors to utilize 13 rigs with terms ranging from six months to three years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of March 31, 2014, the aggregate undiscounted minimum future payments under these drilling rig commitments were approximately $109 million.
	Drilling Commitments
	In December 2011, as part of our Utica joint venture development agreement with Total S.A. (Total) (see Note 9), we committed to spud no less than 90 cumulative Utica wells by December 31, 2012, 270 cumulative wells by December 31, 2013 and 540 cumulative wells by July 31, 2015. Through March 31, 2014, we had spud 488 cumulative Utica wells and had met our 2012 and 2013 commitments. If we fail to meet the drilling commitment at July 31, 2015 for any reason other than a force majeure event, the drilling carry percentage used to determine our promoted well reimbursement will be reduced from 60% to 45% for the number of wells drilled in the subsequent 12-month period represented by the shortfall versus our drilling commitment. As such, any reduction would only affect the timing of the receipt of the drilling carry but not the total drilling carry to be received.
	We have also committed to drill wells in conjunction with our CHK Utica and CHK C-T financial transactions and in conjunction with the formation of the Chesapeake Granite Wash Trust. See Note 6 for discussion of these transactions and commitments.
	Property and Equipment Purchase Commitments
	Much of the oilfield services and other equipment we purchase requires long production lead times. As a result, we have outstanding orders and commitments for such equipment. As of March 31, 2014, we had $117 million of purchase commitments related to future inventory and capital expenditures for oilfield services and other equipment.
	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 VPP transactions. Production purchased under these arrangements is based on market prices at the time of production, and the purchased natural gas and liquids are resold at market prices. See Note 9 for further discussion of our VPP transactions.
	Net Acreage Maintenance Commitments
	Under the terms of our joint venture agreements with Statoil, Total and Sinopec (see Note 9), we are required to extend, renew or replace certain expiring joint leasehold, at our cost, to ensure that the net acreage is maintained in certain designated areas. To date, we have satisfied our replacement commitments under the Statoil and Sinopec agreements. We estimate a shortfall of approximately 14,000 net acres pursuant to our net acreage maintenance commitment with Total under the terms of our Barnett Shale joint venture agreement and have accrued $28 million as of March 31, 2014. Total has disputed our estimate of the shortfall, however, and the cash payment we ultimately make to Total could exceed amounts we have accrued.
	Affiliate Commitments
	Under the terms of our corporate revolving bank credit facility, certain of our subsidiaries, including our oilfield services companies, are not guarantors of the credit facility debt. Transactions between us and our non-guarantor subsidiaries may affect our EBITDA or indebtedness for purposes of our credit facility covenant calculations, but they would have no effect on our consolidated financial statements because the transactions would be eliminated through consolidation. See Note 3 for discussion of our covenant calculations.
	In October 2011, we entered into a services agreement with our wholly owned subsidiary, COO, under which we guarantee the utilization of a portion of COO’s drilling rig and hydraulic fracturing fleets during the term of the agreement. Through October 2016, we are subject to non-utilization fees if we do not operate a specific number of COO’s drilling rigs or utilize a specific number of its hydraulic fracturing fleets. We were not subject to any non-utilization fees in the Current Quarter or the Prior Quarter.
	Other Commitments
	In April 2011, we entered into a master frac service agreement with our equity affiliate, FTS International, Inc. (FTS), which expires on December 31, 2014. Pursuant to this agreement, we are committed to enter into a predetermined number of backstop contracts, providing at least a 10% gross margin to FTS, if utilization of FTS fleets falls below a certain level. To date, we have not been required to enter into any backstop contracts.
	In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Longmont, Colorado, $35 million of which was invested in July 2011 and the remainder of which was payable in separate tranches linked to specified funding and operational milestones. 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 the occurrence of specified milestones. As of March 31, 2014, we had funded our initial $155 million commitment in full and the milestones related to the option had not been met. See Note 10 for further discussion of this investment.
	As part of our normal course of business, we enter into various agreements providing, or otherwise arranging, 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 or in regards to perfecting title to property. 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.
	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 9 for further discussion of our VPP transactions.

Other_Liabilities_Note

Other Liabilities (Note)	3 Months Ended
	Mar. 31, 2014
Other Liabilities Disclosure [Abstract]	'
Other Liabilities Disclosure [Text Block]	'
	Other Liabilities
	Other current liabilities as of March 31, 2014 and December 31, 2013 are detailed below.
			March 31,		December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,499	$	1,409
	Accrued natural gas, oil and NGL drilling and production costs		285		457
	Joint interest prepayments received		530		464
	Accrued compensation and benefits		228		320
	Other accrued taxes		113		161
	Accrued dividends		101		101
	Other		538		599
	Total other current liabilities		$	3,294	$	3,511
	Other long-term liabilities as of March 31, 2014 and December 31, 2013 are detailed below.
			March 31,		December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	242	$	250
	CHK C-T ORRI conveyance obligation(b)		146		149
	Financing obligations		30		31
	Other		433		554
	Total other long-term liabilities		$	851	$	984
	____________________________________________
	(a)	$15 million and $13 million of the total $257 million and $263 million obligations are recorded in other current liabilities as of March 31, 2014 and December 31, 2013, respectively. See Note 6 for further discussion of the transaction.
	(b)	$15 million and $12 million of the total $161 million and $161 million obligations are recorded in other current liabilities as of March 31, 2014 and December 31, 2013, respectively. See Note 6 for further discussion of the transaction.

Equity_Note

Equity (Note)	3 Months Ended
	Mar. 31, 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 for the three months ended March 31, 2014 and 2013:
			Three Months Ended
			March 31,
			2014			2013
			(in thousands)
	Shares issued as of January 1		666,192			666,468
	Restricted stock issuances (net of forfeitures)(a)		(1,236	)		2,631
	Stock option exercises		259			176
	Shares issued as of March 31		665,215			669,275
	___________________________________________
	(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 and liquidation preferences of our cumulative convertible preferred stock for the three months ended March 31, 2014 and 2013:
			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
	March 31, 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 Quarter and the Prior Quarter, 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		11				(5		)		6
	Net other comprehensive income		14				(5		)		9
	Balance, March 31, 2014		$	(153	)		$	—			$	(153	)
			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		(1		)		(5		)		(6		)
	Amounts reclassified from accumulated other comprehensive income		12				6				18
	Net other comprehensive income		11				1				12
	Balance, March 31, 2013		$	(178	)		$	8			$	(170	)
	For the Current Quarter and the Prior Quarter, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed consolidated statements of operations are detailed below.
	Details About Accumulated		Affected Line Item		Three Months Ended
	Other Comprehensive		in the Statement		March 31,
	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		$	11			$	12
	Investments:
	Impairment of investment		Losses on investments		—				6
	Sale of investment		Net gain on sale of investment		(5		)		—
	Total reclassifications for the period, net of tax				$	6			$	18
	Noncontrolling Interests
	Cleveland Tonkawa Financial Transaction. We formed 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 and, until December 31, 2013, it was also required to retain an amount of cash equal to its projected operating funding shortfall for the next six months. The amounts retained, approximately $38 million as of March 31, 2014 and December 31, 2013, were 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 March 31, 2014 and December 31, 2013, the redemption price and the liquidation preference were each approximately $1,230 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 only 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 3 and 21 qualified net wells were added in the Current Quarter and the Prior Quarter, respectively. Through March 31, 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. Under the ORRI obligation, we delivered an ORRI in approximately 3 net wells in the Current Quarter and 22 net wells in the Prior Quarter. Although operations began on April 1, 2012, all wells completed since January 1, 2012 are credited to the ORRI obligation of 1,000 future net wells.
	As of March 31, 2014 and December 31, 2013, $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK C-T. In both the Current Quarter and the Prior Quarter, income of $19 million was attributable to the noncontrolling interests of CHK C-T.
	Utica Financial Transaction. We formed CHK Utica in October 2011 to develop a portion of our Utica Shale natural gas and oil assets. CHK Utica 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 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. Subject to customary minority interest protections afforded the investors by the terms of the CHK Utica limited liability company agreement (the CHK Utica LLC Agreement), as the holder of all the common shares and the sole managing member of CHK Utica, we maintain voting and managerial control of CHK Utica and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $300 million to the ORRI obligation and $950 million 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 Utica LLC Agreement, CHK Utica is required to retain a cash balance equal to the next two quarters of preferred dividend payments. The amount reserved for paying such dividends, approximately $37 million as of March 31, 2014 and December 31, 2013, was reflected as restricted cash on our condensed consolidated balance sheets. In addition, pursuant to the CHK Utica LLC Agreement, with respect to any divestiture proceeds as defined by the agreement, CHK Utica is required to separately account for, and dedicate all of such divestiture proceeds to either (i) capital expenditures made by CHK Utica in connection with its assets or (ii) the redemption of CHK Utica preferred shares.
Dividends on the preferred shares are payable on a quarterly basis at a rate of 7% 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 Utica, we may, at our sole discretion and election at any time after December 31, 2013, distribute certain excess cash of CHK Utica, as determined in accordance with the CHK Utica LLC Agreement. Any such optional distribution of excess cash is allocated 70% to the preferred shares (which is applied toward redemption of the preferred shares) and 30% to the common shares. We may also, at our sole discretion and election, in accordance with the CHK Utica LLC Agreement, cause CHK Utica to redeem the CHK Utica preferred shares for cash, in whole or in part. The preferred shares may be redeemed at a valuation equal to the greater of a 10% internal rate of return or a return on investment of 1.4x, in each case inclusive of dividends paid at the rate of 7% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to October 31, 2018, the optional redemption valuation will increase to provide the investors the greater of a 17.5% internal rate of return or a return on investment of 2.0x. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of March 31, 2014 and December 31, 2013, the redemption price and the liquidation preference were each approximately $1,235 and $1,252, respectively, per preferred share.
We have committed to drill and complete, for the benefit of CHK Utica in the area of mutual interest, a minimum of 50 net wells per year from 2012 through 2016, up to a minimum cumulative total of 250 net wells. CHK Utica is responsible for all capital and operating costs of the wells drilled for the benefit of the entity. If we fail to meet the then-current drilling commitment in any year, we must pay CHK Utica $5 million for each well we are short of such drilling commitment. CHK Utica also receives its proportionate share of the benefit of the drilling carry associated with our joint venture with Total in the Utica Shale. See Note 9 for further discussion of the joint venture. Under the development agreement, approximately 22 and 28 qualified net wells were added in the Current Quarter and the Prior Quarter, respectively. Through March 31, 2014, we had met all current drilling commitments associated with the CHK Utica transaction.
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. Under the ORRI obligation, we delivered an ORRI in approximately 32 new net wells in the Current Quarter and 14 net wells in the Prior Quarter. 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. Through March 31, 2014, we were on target to meet the ORRI conveyance commitments associated with the CHK Utica transaction.
As of March 31, 2014 and December 31, 2013, $807 million of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK Utica. In the Current Quarter and the Prior Quarter, income of approximately $19 million and $22 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 will not be 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 March 31, 2014 and 2013, we had drilled or caused to be drilled approximately 89 and 64 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $65 million and $120 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. 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 Quarter and the Prior Quarter, the Trust declared and paid the following distributions:
Production Period		Distribution Date		Cash Distribution				Cash Distribution
				per				per
				Common Unit				Subordinated Unit
September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
We have determined that the Trust constitutes a VIE and that Chesapeake is the primary beneficiary. As a result, the Trust is included in our condensed consolidated financial statements. As of March 31, 2014 and December 31, 2013, $306 million and $314 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to the Trust. In both the Current Quarter and the Prior Quarter, income of approximately $5 million was attributable to the Trust’s noncontrolling interests in our condensed consolidated statements of operations. See Note 11 for further discussion of VIEs.
Wireless Seismic, Inc. We have a controlling 51% equity interest in Wireless Seismic, Inc. (Wireless), a privately owned company engaged in research, development and production of wireless seismic systems and any related technology that deliver seismic information obtained from standard geophones in real time to laptop and desktop computers. As of March 31, 2014 and December 31, 2013, $8 million and $9 million, respectively, of noncontrolling interests on our condensed consolidated balance sheets were attributable to Wireless. In both the Current Quarter and the Prior Quarter, losses of $1 million were attributable to noncontrolling interests of Wireless in our condensed consolidated statements of operations.

ShareBased_Compensation_Note

Share-Based Compensation (Note)	3 Months Ended
	Mar. 31, 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, stock options and performance share units (PSUs) granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. 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 or dividend equivalents on unvested shares. A summary of the changes in unvested shares of restricted stock during the Current Quarter 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		3,943			$	25.13
	Vested		(2,350	)		$	26.41
	Forfeited		(638	)		$	25.69
	Unvested shares as of March 31, 2014		14,355			$	23.26
	The aggregate intrinsic value of restricted stock that vested during the Current Quarter was approximately $62 million based on the stock price at the time of vesting.
	As of March 31, 2014, there was $255 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 2.5 years.
	The vesting of certain restricted stock grants may result in state and federal income tax 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, we recognized excess tax benefits related to restricted stock of $3 million and during the Prior Quarter we recognized reductions in tax benefits related to restricted stock of $10 million, which were recorded as adjustments to additional paid-in capital and deferred income taxes.
	Stock Options. In the Current Quarter and the Prior Quarter, we granted members of senior management stock options that will vest ratably over a three-year period. In the Prior Quarter, we also granted retention awards to certain officers of stock options that will vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Outstanding options generally expire ten years from the date of grant.
	We utilize the Black-Scholes option pricing model to measure the fair value of stock options. The expected life of an option is determined using the "simplified method", as there is no adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility of Chesapeake stock over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy over the expected life of the option. The Company used the following assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter:
	Expected option life - years		6
	Volatility		48.33	%
	Risk-free interest rate		1.97	%
	Dividend yield		1.36	%
	The following table provides information related to stock option activity during the Current Quarter:
			Number of			Weighted			Weighted		Aggregate
			Shares			Average			Average		Intrinsic
			Underlying			Exercise			Contract		Value(a)
			Options			Price			Life in
						Per Share			Years
			(in thousands)								($ in millions)
	Outstanding at January 1, 2014		5,268			$	19.28		6.66		$	41
	Granted		786			$	25.71
	Exercised		(270	)		$	18.23				$	2
	Expired		—			$	—
	Outstanding at March 31, 2014		5,784			$	20.2		7.15		$	31
	Exercisable at March 31, 2014		1,766			$	18.95		3.72		$	12
	___________________________________________
	(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
	As of March 31, 2014, there was $21 million of total unrecognized compensation expense related to stock options. The expense is expected to be recognized over a weighted average period of approximately 2.4 years.
	The vesting of certain stock option grants may result in state and federal income tax 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 Prior Quarter, we recognized excess tax benefits related to stock options of a nominal amount and $0, respectively. All amounts were recorded as adjustments to additional paid-in capital and deferred income taxes.
	Compensation Expenses. We recorded the following compensation expenses related to restricted stock and stock options during the Current Quarter and the Prior Quarter:
			Three Months Ended
			March 31,
			2014				2013
			($ in millions)
	General and administrative expenses		$	12			$	20
	Natural gas and oil properties		7				21
	Natural gas, oil and NGL production expenses		4				6
	Marketing, gathering and compression expenses		2				3
	Oilfield services expenses		2				3
	Total		$	27			$	53
	Liability-Classified Awards
	Performance Share Units. In 2012, 2013 and 2014, we granted PSUs to senior management under our Long Term Incentive Plan 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 the performance metrics established by the Compensation Committee of the Board of Directors, which include relative and absolute total shareholder return (TSR) and, for certain of the awards, the achievement of operational performance goals such as production and proved reserve growth. The TSR metric is considered a market condition and generally requires a Monte Carlo simulation to determine the fair value.
	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 following table presents a summary of our PSU awards as of March 31, 2014:
			Units			Fair Value			Fair Value				Liability for
						as of							Vested
						Grant Date							Amount
						($ in millions)
	2012 Awards (a)
	Payable 2015		834,248			$	23		$	21			$	21
	2013 Awards
	Payable 2016		1,600,438			$	35		$	52			$	45
	2014 Awards
	Payable 2017		620,669			$	17		$	16			$	4
___________________________________________
(a)	In the Current Quarter and the Prior Quarter, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
Compensation Expenses. We recorded the following compensation expenses related to PSUs during the Current Quarter and the Prior Quarter:
		Three Months Ended
		March 31,
		2014				2013
		($ in millions)
Natural gas and oil properties		$	1			$	4
General and administrative expenses		(1		)		5
Marketing, gathering and compression expenses		—				2
Total		$	—			$	11

Derivative_and_Hedging_Activit

Derivative and Hedging Activities (Note)	3 Months Ended
	Mar. 31, 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 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 our 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 March 31, 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 price differential to NYMEX from a specified delivery point. Our current natural gas basis protection swaps have negative differentials to NYMEX. Chesapeake receives a payment from the counterparty if the price differential is greater than the stated terms of the contract and pays the counterparty if the price differential is less than the stated terms of the contract. Our current oil basis protection swaps have positive differentials to NYMEX. Chesapeake receives a payment from the counterparty if the price differential is less than the stated terms of the contract and pays the counterparty if the price differential is greater than the stated terms of the contract.
	The estimated fair values of our natural gas and oil derivative instrument assets (liabilities) as of March 31, 2014 and December 31, 2013 are provided below.
			31-Mar-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		394			$	(125	)		448			$	(23	)
	Three-way collars		387			(48		)		288			(7		)
	Call options		193			(202		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		151			(14		)		68			3
	Total natural gas		1,125			(389		)		1,009			(237		)
	Oil (mmbbl):
	Fixed-price swaps		22.8			(81		)		25.3			(50		)
	Call options		41.9			(257		)		42.5			(265		)
	Basis protection swaps		0.3			1				0.4			1
	Total oil		65			(337		)		68.2			(314		)
	Total estimated fair value					$	(726	)					$	(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 March 31, 2014 and December 31, 2013, our interest rate derivative instruments consisted of swaps. Chesapeake enters 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 facilities borrowings.
	The notional amount of our interest rate derivative liabilities as of March 31, 2014 and December 31, 2013 was $2.250 billion. The estimated fair value of our interest rate derivative liabilities as of March 31, 2014 and December 31, 2013 was $80 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 seven years, we will recognize $13 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 an asset of $7 million as of March 31, 2014. The euro-denominated debt in long-term debt has been adjusted to $473 million as of March 31, 2014 using an exchange rate of $1.3769 to €1.00.
	Effect of Derivative Instruments – Condensed Consolidated Balance Sheets
	The following table presents the fair value and location of each classification of derivative instrument included in the condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013 on a gross basis and after same-counterparty netting:
			March 31, 2014
	Balance Sheet Classification		Gross Fair Value				Amounts Netted				Net Fair Value Presented
							in Condensed Consolidated				in Condensed Consolidated
							Balance Sheet				Balance Sheet
			($ in millions)
	Commodity Contracts
	Short-term derivative asset		$	13			$	(11	)		$	2
	Long-term derivative asset		3				1				4
	Short-term derivative liability		(425		)		11				(414		)
	Long-term derivative liability		(317		)		(1		)		(318		)
	Total commodity contracts		(726		)		—				(726		)
	Interest Rate Contracts
	Short-term derivative liability		(3		)		—				(3		)
	Long-term derivative liability		(77		)		—				(77		)
	Total interest rate contracts		(80		)		—				(80		)
	Foreign Currency Contracts(a)
	Long-term derivative asset		7				—				7
	Total foreign currency contracts		7				—				7
	Total Derivatives		$	(799	)		$	—			$	(799	)
			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 March 31, 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 and the Prior Quarter are presented below.
		Three Months Ended
		March 31,
		2014				2013
		($ in millions)
Natural gas, oil and NGL sales		$	2,148			$	1,595
Losses on undesignated natural gas, oil and NGL derivatives		(365		)		(123		)
Losses on terminated cash flow hedges		(17		)		(19		)
Total natural gas, oil and NGL sales		$	1,766			$	1,453
The components of interest expense for the Current Quarter and the Prior Quarter are presented below.
		Three Months Ended
		March 31,
		2014				2013
		($ in millions)
Interest expense on senior notes		$	180			$	186
Interest expense on term loans		29				29
Amortization of loan discount, issuance costs and other		19				19
Interest expense on credit facilities		8				12
Gains on terminated fair value hedges		(1		)		—
(Gains) losses on undesignated interest rate derivatives		(18		)		4
Capitalized interest		(178		)		(229		)
Total interest expense		$	39			$	21
Effect of Derivative Instruments – Accumulated Other Comprehensive Income (Loss)
A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Three Months Ended
		March 31,
		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		4				3				(2		)		(1		)
Losses reclassified to income		18				11				19				12
Balance, end of period		$	(247	)		$	(153	)		$	(287	)		$	(178	)
Approximately $148 million of the $153 million of accumulated other comprehensive loss as of March 31, 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 March 31, 2014, we expect to transfer approximately $23 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022.
Credit Risk Considerations
Over-the-counter traded derivative instruments expose us to our counterparties’ credit risk. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of March 31, 2014, our natural gas, oil and interest rate derivative instruments were spread among 16 counterparties.
Hedging Facility
Our secured commodity hedging facility with 17 counterparties provides approximately 1.063 bboe of hedging capacity for natural gas, oil and NGL price derivatives and 1.063 bboe for basis derivatives with an aggregate mark-to-market capacity of $17.0 billion. It 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, indentures, term loan and equipment master lease agreements. 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 March 31, 2014, we had hedged under the facility 224 mmboe of our future production with price derivatives and 26 mmboe with basis derivatives.
Fair Value
The fair value of most 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 March 31, 2014 and December 31, 2013:
As of March 31, 2014		Quoted				Significant				Significant				Total
		Prices in				Other				Unobservable				Fair Value
		Active				Observable				Inputs
		Markets				Inputs				(Level 3)
		(Level 1)				(Level 2)
						($ in millions)
Derivative Assets (Liabilities):
Commodity assets		$	—			$	10			$	6			$	16
Commodity liabilities		—				(229		)		(513		)		(742		)
Interest rate liabilities		—				(80		)		—				(80		)
Foreign currency assets		—				7				—				7
Total derivatives		$	—			$	(292	)		$	(507	)		$	(799	)
As of 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)
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 Quarter and the Prior Quarter 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)		(80		)		—
Total purchases, issuances, sales and settlements:
Settlements		55				—
Transfers(b)		(4		)		—
Ending Balance as of March 31, 2014		$	(507	)		$	—
Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
Total gains (losses) (realized/unrealized):
Included in earnings(a)		194				(1		)
Total purchases, issuances, sales and settlements:
Sales		—				(1		)
Settlements		37				—
Ending Balance as of March 31, 2013		$	(785	)		$	(2	)
___________________________________________
(a)		Natural Gas, Oil and								Interest Expense
		NGL Sales
		2014				2013				2014				2013
		($ in millions)
Total gains (losses) included in earnings for the		$	(80	)		$	194			$	—			$	(1	)
period
Change in unrealized gains (losses) related to		$	(57	)		$	191			$	—			$	(2	)
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 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.
Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
Instrument		Unobservable		Range		Weighted			Fair Value
Type		Input				Average			March 31, 2014(a)
									($ in millions)
Oil trades		Oil price volatility curves		10.56% - 21.78%		15.43	%		$	(256	)
Natural gas trades		Natural gas price volatility		18.03% - 38.37%		24.32	%		$	(251	)
		curves
___________________________________________
(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_D

Natural Gas and Oil Property Divestitures (Note)	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
Mergers, Acquisitions and Dispositions Disclosure [Text Block]	'
	Natural Gas and Oil Property Divestitures
	During the Current Quarter and the Prior Quarter, excluding proceeds received from selling additional interests in our joint venture leasehold described under Joint Ventures below, we received proceeds of approximately $41 million and $165 million, respectively, related to divestitures of noncore 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
	As of March 31, 2014, we had entered into eight significant joint ventures with other leading energy companies pursuant to which we sold a portion of our leasehold, producing properties and other assets located in eight different resource plays and received cash of $8.0 billion and commitments by our counterparties to pay our share of future drilling and completion costs of $9.0 billion. In each of these joint ventures, Chesapeake serves as the operator and conducts all drilling, completion and operations, the majority of leasing and, in certain transactions, marketing activities for the project. The carries paid by a joint venture partner are for a specified percentage of our drilling and completion costs. In addition, a joint venture partner is responsible for its proportionate share of drilling and completion costs as a working interest owner. We bill our joint venture partners for their drilling carries at the same time we bill them and other joint working interest owners for their share of drilling costs as they are incurred. For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. The transactions are detailed below.
	Primary		Joint	Joint		Interest		Initial Proceeds(b)				Total				Total Initial			Drilling
	Play		Venture	Venture		Sold						Drilling				Proceeds			Carries
			Partner(a)	Date								Carries				and Drilling			Remaining(c)
																Carries
								($ in millions)
	Mississippi Lime		Sinopec	Jun-13		50.00%		$	949		(d)	$	—			$	949		$	—
	Utica		TOT	December 2011		25.00%		610				1,422			(e)	2,032			478
	Niobrara		CNOOC	Feb-11		33.30%		570				697			(f)	1,267			64
	Eagle Ford		CNOOC	Nov-10		33.30%		1,120				1,080				2,200			—
	Barnett		TOT	Jan-10		25.00%		800				1,403				2,203			—
	Marcellus		STO	Nov-08		32.50%		1,250				2,125				3,375			—
	Fayetteville		BP	September 2008		25.00%		1,100				800				1,900			—
	Haynesville & Bossier		FCX	Jul-08		20.00%		1,650				1,508				3,158			—
								$	8,049			$	9,035			$	17,084		$	542
	____________________________________________
	(a)	Joint venture partners are Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Freeport-McMoRan Copper & Gold (FCX), formerly known as Plains Exploration & Production Company.
	(b)	Excludes closing and post-closing adjustments.
	(c)	As of March 31, 2014.
	(d)	Excludes $71 million of net proceeds (or 7% of the total transaction) expected to be received pursuant to certain post-closing adjustments and approximately $90 million received at closing for closing adjustments.
	(e)	The Utica drilling carry covers 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize this drilling carry commitment prior to expiration. See Note 4 for further discussion of the Utica drilling carries.
	(f)	The Niobrara drilling carry covers 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize this drilling carry commitment prior to expiration.
	During the Current Quarter and the Prior Quarter, our drilling and completion costs included the benefit of approximately $188 million and $180 million, respectively, in drilling and completion carries paid by our joint venture partners.
	During the Current Quarter and the Prior Quarter, we sold interests in additional leasehold we acquired in the Marcellus, Barnett, Utica, Haynesville, Eagle Ford, Mid-Continent and Niobrara Shale plays to our joint venture partners for approximately $8 million and $25 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.
	Our outstanding VPPs consist 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
	5		Aug-09	South Texas		370				67			0.2			—		68
	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
						$	6,031			1,216			5.7			14		1,334
	The volumes produced on behalf of our VPP buyers for the Current Quarter and the Prior Quarter were as follows:
			Three Months Ended March 31, 2014											Three Months Ended March 31, 2013
	VPP #		Natural Gas		Oil			NGL			Total			Natural Gas			Oil		NGL		Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)			(bcf)			(mbbl)		(mbbl)		(bcfe)
	10		2.8		109			345.2			5.5			3.7			154		407.7		6.9
	9		4		49			106.5			4.9			4.4			56.2		118.8		5.5
	8		15.7		—			—			15.7			18			—		—		18
	6		1.1		6			—			1.2			1.2			6		—		1.2
	5		1.7		6.3			—			1.8			2			6		—		2
	4		2.3		12.4			—			2.4			2.6			14.2		—		2.7
	3		1.9		—			—			1.9			2.1			—		—		2.1
	2		2.4		—			—			2.4			2.7			—		—		2.7
1		3.6		—			—			3.6			3.8			—		—		3.8
		35.5		182.7			451.7			39.4			40.5			236.4		526.5		44.9
The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2014 were as follows:
			Volume Remaining as of March 31, 2014
VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
		(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
10		95	45.8			1.6			5.6			89.2
9		83	84.7			1			2.2			104
8		17	80.9			—			—			80.9
6		70	20.3			0.1			—			21.1
5		34	15.2			0.1			—			15.5
4		33	22			0.1			—			22.7
3		64	29.2			—			—			29.2
2		61	17.6			—			—			17.6
1		105	101.8			—			—			101.8
			417.5			2.9			7.8			482

Investments_Note

Investments (Note)	3 Months Ended
	Mar. 31, 2014
Investments [Abstract]	'
Investments Disclosure [Text Block]	'
	Investments
	A summary of our investments, including our approximate ownership percentage as of March 31, 2014 and December 31, 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	March 31,	December 31,	March 31,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	129	$	138
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Sundrop Fuels, Inc.	Equity	56%	56%	134		135
	Other	—	—%	—%	25		61
	Total investments				$	288	$	477
	FTS International, Inc. FTS International, Inc. (FTS), based in Fort Worth, Texas, is a privately held company which, through its subsidiaries, provides hydraulic fracturing and other services to oil and gas companies. During the Current Quarter, we recorded negative equity method and other adjustments, prior to intercompany profit eliminations, of $15 million for our share of FTS’s net loss and recorded an accretion adjustment of $6 million related to the excess of our underlying equity in net assets of FTS over our carrying value.
	As of March 31, 2014, the carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $48 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.
	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 Quarter, 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.
	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 Quarter, we recorded a $3 million charge related to our share of Sundrop's net loss and capitalized interest totaling $2 million 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 $65 million.
	Other. In the Current Quarter, we sold an equity investment in a natural gas trading and management firm for cash proceeds of $30 million and recorded a loss of $6 million associated with the transaction.

Variable_Interest_Entities_Not

Variable Interest Entities (Note)	3 Months Ended
	Mar. 31, 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, please see Noncontrolling Interests in Note 6. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.
	The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of March 31, 2014, $1 million of cash and cash equivalents, approximately $298 million of net natural gas and oil properties, $6 million of short-term derivative liabilities and $19 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.

Other_Property_and_Equipment_N

Other Property and Equipment (Note)	3 Months Ended
	Mar. 31, 2014
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]	'
Other Property and Equipment [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 and the Prior Quarter is as follows:
		Three Months Ended
		March 31,
		2014			2013
		($ in millions)
	Natural gas compressors	$	(26	)	$	—
	Gathering systems and treating plants	3			(69		)
	Drilling rigs and equipment	2			1
	Buildings and land	—			22
	Other	(2		)	(3		)
	Total net gains on sales of fixed assets	$	(23	)	$	(49	)
	Natural Gas Compressors. In the Current Quarter, we sold 102 compressors and related equipment to Access Midstream Partners, L.P. (NYSE:ACMP) 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 interest in certain gathering system assets in Pennsylvania to Western Gas Partners, LP (NYSE:WES) for proceeds of approximately $134 million. We recorded a $55 million gain associated with this transaction.
	Buildings and Land. In the Prior Quarter, we recorded net losses of $22 million on sales of buildings and land located primarily in our Barnett Shale operating area.
	Assets Held for Sale
	In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of March 31, 2014 we were continuing to pursue the sale of various land and buildings located in the Fort Worth, Texas area. The land and buildings in both the Oklahoma City and Fort Worth areas are reported under our other segment. We are also pursuing the sale of various other property and equipment, including certain drilling rigs, compressors and gathering systems. See Note 19 for more information on our compressors held for sale as of March 31, 2014 that were subsequently sold in April 2014. The drilling rigs are reported under our oilfield services operating segment, and the compressors and gathering systems are reported under our marketing, gathering and compression operating segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets qualified as held for sale as of March 31, 2014. Natural gas and oil properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets held for sale on our condensed consolidated balance sheets as of March 31, 2014 and December 31, 2013 is detailed below.
		March 31,			December 31,
		2014			2013
		($ in millions)
	Natural gas gathering systems and treating plants, net of accumulated depreciation	$	10		$	11
	Oilfield services equipment, net of accumulated depreciation	58			29
	Compressors, net of accumulated depreciation	322			285
	Buildings and land, net of accumulated depreciation	237			405
	Property and equipment held for sale, net	$	627		$	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 during the Current Quarter 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. Approximately $116 million, primarily consisting of land that had been classified as held for sale as of December 31, 2013, was reclassified as held for use as of March 31, 2014. There was no impact to the statements of operations related to this reclassification in the Current Quarter.

Impairments_of_Fixed_Assets_an

Impairments of Fixed Assets and Other (Note)	3 Months Ended
	Mar. 31, 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 and the Prior Quarter is as follows:
		Three Months Ended
		March 31,
		2014		2013
		($ in millions)
	Drilling rigs and equipment	$	20	$	—
	Buildings and land	—		27
	Total impairments of fixed assets and other	$	20	$	27
	Drilling Rigs and Equipment. In the Current Quarter, we purchased 20 leased rigs and equipment from various lessors for an aggregate purchase price of $77 million and paid approximately $8 million in early lease termination costs, which is included in impairments of fixed assets and other in the condensed consolidated statement of operations. In addition, we impaired approximately $12 million of leasehold improvements and other costs associated with these transactions. See Note 4 for a description of the master lease agreements. We measured the fair value of these assets based on recent sales information for comparable rigs and equipment. The drilling rigs and equipment are included in our oilfield services operating segment.
	Buildings and Land. In the Prior Quarter, we recognized $27 million of impairment losses on certain of our buildings and land in the Oklahoma City area (other than our core campus) classified as held for sale. We measured the fair value of these assets based on purchase offers we received from third parties. The buildings and land are included in our other operating segment.
	Nonrecurring Fair Value Measurements
	Fair value measurements for impairments on the drilling rigs and equipment discussed above were based on recent sales information for comparable rigs and 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 for impairments on the buildings and land discussed above were based on a bid we received from a third party. Since the input used was 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)	3 Months Ended
	Mar. 31, 2014
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Activities Disclosure [Text Block]	'
	Restructuring and Other Termination Costs
	On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and CEO and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In the Prior Quarter, we incurred charges of approximately $64 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 $56 million of expense for the Prior Quarter.
	During the Prior Quarter, we also incurred charges of approximately $13 million related to other workforce reductions, including separations of executive officers other than the CEO. Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment. Below is a summary of our restructuring and other termination costs for the Current Quarter and the Prior Quarter:
			Three Months Ended
			March 31,
			2014			2013
			($ in millions)
	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)		(4		)	13
	Estimated aircraft usage benefits		—			7
	Total termination benefits provided to Mr. McClendon		(4		)	64
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			30
	Acceleration of stock-based compensation		—			24
	Other termination benefits		—			2
	Total termination benefits provided to VSP participants		—			56
	Other termination benefits(a)		(3		)	13
	Total restructuring and other termination costs		$	(7	)	$	133
	____________________________________________
	(a)	The Current Quarter amount primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 7.

Fair_Value_Measurements_Note

Fair Value Measurements (Note)	3 Months Ended
	Mar. 31, 2014
Fair Value Disclosures [Abstract]	'
Fair Value Measurements Disclosure [Text Block]	'
	Fair Value Measurements
	Recurring Fair Value Measurement
	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.
	The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2014 and December 31, 2013:
	As of March 31, 2014	Quoted			Significant		Significant		Total
		Prices in			Other		Unobservable		Fair Value
		Active			Observable		Inputs
		Markets			Inputs		(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	Financial Assets (Liabilities):
	Other current assets	$	78		$	—	$	—	$	78
	Other current liabilities	(80		)	—		—		(80		)
	Total	$	(2	)	$	—	$	—	$	(2	)
	As of 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)
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—	$	—	$	80
	Other current liabilities	(82		)	—		—		(82		)
	Total	$	(2	)	$	—	$	—	$	(2	)
	See Note 3 for information regarding fair value of other financial instruments. See Note 8 for information regarding fair value measurement of derivatives. See Note 13 regarding nonrecurring fair value measurements.

Segment_Information_Note

Segment Information (Note)	3 Months Ended
	Mar. 31, 2014
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]	'
Segment Information Disclosure [Text Block]	'
	Segment Information
	We have three reportable operating segments, each of which is managed separately because of the nature of its products and services. 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. The oilfield services operating segment is 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.
	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 the marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. Such amounts totaled $2.408 billion and $1.748 billion for the Current Quarter and the Prior Quarter, respectively. Revenues generated by the oilfield services operating segment for work performed for Chesapeake’s exploration and production operating segment are reclassified to the full cost pool based on Chesapeake’s ownership interest. Revenues reclassified totaled $271 million and $352 million for the Current Quarter and the Prior Quarter, respectively. No income is recognized in our condensed consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. The following table presents selected financial information for Chesapeake’s operating segments:
		Exploration		Marketing,			Oilfield			Other			Intercompany			Consolidated
		and		Gathering			Services						Eliminations			Total
		Production		and
				Compression
		($ in millions)
	Three Months Ended March 31, 2014:
	Revenues	$	1,766	$	5,423		$	510		$	26		$	(2,679	)	$	5,046
	Intersegment revenues	—		(2,408		)	(271		)	—			2,679			—
	Total revenues	$	1,766	$	3,015		$	239		$	26		$	—		$	5,046
	Income (Loss) Before	$	687	$	105		$	(42	)	$	60		$	(64	)	$	746
	Income Taxes
	Three Months Ended March 31, 2013:
	Revenues	$	1,453	$	3,529		$	538		$	10		$	(2,106	)	$	3,424
	Intersegment revenues	—		(1,748		)	(352		)	(6		)	2,106			—
	Total revenues	$	1,453	$	1,781		$	186		$	4		$	—		$	3,424
	Income (Loss) Before	$	170	$	129		$	22		$	(58	)	$	(98	)	$	165
	Income Taxes
	As of
	March 31, 2014:
	Total Assets	$	36,102	$	2,950		$	2,058		$	5,516		$	(4,021	)	$	42,605
	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)	3 Months Ended
	Mar. 31, 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 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our 100% owned subsidiaries on a senior unsecured basis. Our oilfield services subsidiaries are separately capitalized and are not guarantors of our senior notes or our other debt obligations, but are subject to the covenants and guarantees in the oilfield services revolving bank credit facility agreement described in Note 3 that limit their ability to pay dividends or distributions or make loans to Chesapeake. In addition, subsidiaries with noncontrolling interests, consolidated variable interest entities and certain de minimis subsidiaries are non-guarantors.
	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 March 31, 2014 and December 31, 2013 and for the three months ended March 31, 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 MARCH 31, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	974		$	—		$	75		$	(45	)	$	1,004
	Restricted cash		—			—			82			(7		)	75
	Other		88			2,862			623			(377		)	3,196
	Intercompany receivable, net		25,431			—			—			(25,431		)	—
	Total Current Assets		26,493			2,862			780			(25,860		)	4,275
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,891			3,075			(94		)	32,872
	Other property and equipment, net		—			2,523			1,501			(1		)	4,023
	Property and equipment held for		—			569			58			—			627
	sale, net
	Total Property and Equipment,		—			32,983			4,634			(95		)	37,522
	Net
	LONG-TERM ASSETS:
	Other assets		109			962			109			(372		)	808
	Investments in subsidiaries and		2,387			(201		)	—			(2,186		)	—
	intercompany advances
	TOTAL ASSETS		$	28,989		$	36,606		$	5,523		$	(28,513	)	$	42,605
	CURRENT LIABILITIES:
	Current liabilities		$	550		$	5,445		$	392		$	(429	)	$	5,958
	Intercompany payable, net		—			24,922			257			(25,179		)	—
	Total Current Liabilities		550			30,367			649			(25,608		)	5,958
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,539			—			1,114			—			12,653
	Deferred income tax liabilities		293			2,834			1,117			(416		)	3,828
	Other long-term liabilities		266			1,018			777			(372		)	1,689
	Total Long-Term Liabilities		12,098			3,852			3,008			(788		)	18,170
	EQUITY:
	Chesapeake stockholders’ equity		16,341			2,387			1,866			(4,253		)	16,341
	Noncontrolling interests		—			—			—			2,136			2,136
	Total Equity		16,341			2,387			1,866			(2,117		)	18,477
	TOTAL LIABILITIES AND EQUITY		$	28,989		$	36,606		$	5,523		$	(28,513	)	$	42,605
	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			2,392			616			(367		)	2,744
	Intercompany receivable, net		25,369			—			—			(25,369		)	—
	Total Current Assets		26,271			2,392			737			(25,744		)	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		—			2,315			1,497			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			32,311			4,639			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,146			111			(376		)	992
	Investments in subsidiaries and		2,349			(251		)	—			(2,098		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,598		$	5,487		$	(28,034	)	$	41,782
CURRENT LIABILITIES:
Current liabilities		$	300		$	5,211		$	379		$	(375	)	$	5,515
Intercompany payable, net		—			24,752			593			(25,345		)	—
Total Current Liabilities		300			29,963			972			(25,720		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,264			847			87			3,407
Other liabilities		396			1,022			788			(372		)	1,834
Total Long-Term Liabilities		12,436			3,286			2,690			(285		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,349			1,825			(4,174		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,349			1,825			(2,029		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,598		$	5,487		$	(28,034	)	$	41,782
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	1,545		$	222		$	(1	)	$	1,766
Marketing, gathering and compression		—			3,014			1			—			3,015
Oilfield services		—			—			536			(271		)	265
Total Revenues		—			4,559			759			(272		)	5,046
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			269			19			—			288
Production taxes		—			49			1			—			50
Marketing, gathering and compression		—			2,979			1			—			2,980
Oilfield services		—			17			437			(234		)	220
General and administrative		—			53			26			—			79
Restructuring and other termination costs		—			(7		)	—			—			(7		)
Natural gas, oil and NGL depreciation,		—			568			62			(2		)	628
depletion and amortization
Depreciation and amortization of other		—			39			74			(35		)	78
assets
Impairment of natural gas and oil properties		—			—			59			(59		)	—
Impairments of fixed assets and other		—			—			20			—			20
Net gains on sales of fixed assets		—			(24		)	1			—			(23		)
Total Operating Expenses		—			3,943			700			(330		)	4,313
INCOME FROM OPERATIONS		—			616			59			58			733
OTHER INCOME (EXPENSE):
Interest expense		(192		)	—			(21		)	174			(39		)
Losses on investments		—			(15		)	—			(6		)	(21		)
Gain on sale of investment		—			67			—			—			67
Other income (loss)		344			(141		)	1			(198		)	6
Equity in net earnings of subsidiary		330			(17		)	—			(313		)	—
Total Other Income (Expense)		482			(106		)	(20		)	(343		)	13
INCOME BEFORE INCOME TAXES		482			510			39			(285		)	746
INCOME TAX EXPENSE		57			198			15			10			280
NET INCOME		425			312			24			(295		)	466
Net income attributable to		—			—			—			(41		)	(41		)
noncontrolling interests
NET INCOME ATTRIBUTABLE		425			312			24			(336		)	425
TO CHESAPEAKE
Other comprehensive income		2			7			—			—			9
COMPREHENSIVE INCOME		$	427		$	319		$	24		$	(336	)	$	434
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED MARCH 31, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	1,322		$	128		$	3		$	1,453
Marketing, gathering and compression		—			1,778			3			—			1,781
Oilfield services		—			—			554			(364		)	190
Total Revenues		—			3,100			685			(361		)	3,424
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			296			11			—			307
Production taxes		—			51			2			—			53
Marketing, gathering and compression		—			1,742			3			—			1,745
Oilfield services		—			23			426			(294		)	155
General and administrative		—			87			23			—			110
Restructuring and other termination costs		—			131			2			—			133
Natural gas, oil and NGL depreciation,		—			591			57			—			648
depletion and amortization
Depreciation and amortization of other		—			48			71			(41		)	78
assets
Impairment of natural gas and oil		—			—			91			(91		)	—
properties
Impairments of fixed assets and other		—			27			—			—			27
Net gains on sales of fixed assets		—			(49		)	—			—			(49		)
Total Operating Expenses		—			2,947			686			(426		)	3,207
INCOME FROM OPERATIONS		—			153			(1		)	65			217
OTHER INCOME (EXPENSE):
Interest expense		(219		)	(8		)	(16		)	222			(21		)
Losses on investments		—			(37		)	—			—			(37		)
Other income		216			42			(2		)	(250		)	6
Equity in net earnings (losses) of		60			(87		)	—			27			—
subsidiary
Total Other Income (Expense)		57			(90		)	(18		)	(1		)	(52		)
INCOME (LOSS) BEFORE INCOME TAXES		57			63			(19		)	64			165
INCOME TAX EXPENSE (BENEFIT)		(1		)	57			(7		)	14			63
NET INCOME (LOSS)		58			6			(12		)	50			102
Net income attributable to		—			—			—			(44		)	(44		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		58			6			(12		)	6			58
TO CHESAPEAKE
Other comprehensive income (loss)		(2		)	14			—			—			12
COMPREHENSIVE INCOME (LOSS)		$	56		$	20		$	(12	)	$	6		$	70
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
THREE MONTHS ENDED MARCH 31, 2014
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	1,027		$	264		$	—		$	1,291
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(956		)	(128		)	—			(1,084		)
properties
Proceeds from divestitures of proved		—			48			1			—			49
and unproved properties
Additions to other property and		—			(319		)	(118		)	—			(437		)
equipment
Other investing activities		—			442			5			26			473
Net Cash Used In Investing		—			(785		)	(240		)	26			(999		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities		—			140			281			—			421
borrowings
Payments on credit facilities borrowings		—			(140		)	(222		)	—			(362		)
Other financing activities		(116		)	47			(45		)	(70		)	(184		)
Intercompany advances, net		291			(289		)	(2		)	—			—
Net Cash Provided By (Used In)		175			(242		)	12			(70		)	(125		)
Financing Activities
Net increase (decrease) in cash and cash		175			—			36			(44		)	167
equivalents
Cash and cash equivalents, beginning of		799			—			39			(1		)	837
period
Cash and cash equivalents, end of period		$	974		$	—		$	75		$	(45	)	$	1,004
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
THREE MONTHS ENDED MARCH 31, 2013
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	790		$	146		$	(12	)	$	924
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(1,643		)	(216		)	—			(1,859		)
properties
Proceeds from divestitures of proved		—			138			52			—			190
and unproved properties
Additions to other property and		—			(186		)	(144		)	—			(330		)
equipment
Other investing activities		—			135			74			45			254
Net Cash Used In Investing		—			(1,556		)	(234		)	45			(1,745		)
Activities
CASH FLOWS FROM FINANCING
ACTIVITIES:
Proceeds from credit facilities		—			3,395			237			—			3,632
borrowings
Payments on credit facilities		—			(2,563		)	(248		)	—			(2,811		)
borrowings
Other financing activities		(133		)	(94		)	6			(33		)	(254		)
Intercompany advances, net		(95		)	28			67			—			—
Net Cash Provided By (Used		(228		)	766			62			(33		)	567
In) Financing Activities
Net increase in cash and cash equivalents		(228		)	—			(26		)	—			(254		)
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	—		$	—		$	33		$	—		$	33
___________________________________________
(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 of $228 million, which was 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)	3 Months Ended
	Mar. 31, 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 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 financial statements.

Subsequent_Events_Note

Subsequent Events (Note)	3 Months Ended
	Mar. 31, 2014
Subsequent Events [Abstract]	'
Subsequent Events Disclosure [Text Block]	'
	Subsequent Events
	On April 10, 2014, we sold 337 compressors and related equipment to Exterran Partners, L.P. for approximately $362 million.
	On April 24, 2014, we issued $3.0 billion in aggregate principal amount of senior notes at par. The offering included two series of notes: $1.5 billion in aggregate principal amount of Floating Rate Senior Notes due 2019 and $1.5 billion in aggregate principal amount of 4.875% Senior Notes due 2022. We used a portion of the net proceeds of $2.966 billion to repay the borrowings under, and terminate, our term loan credit facility. We will use the remaining proceeds along with cash on hand to redeem approximately $97 million aggregate principal amount of 6.875% Senior Notes due 2018 and to purchase outstanding 9.5% Senior Notes due 2015 through a tender offer that we commenced concurrently with the senior notes offering. On April 24, 2014, we purchased approximately $946 million aggregate principal amount of the 9.5% Senior Notes due 2015 that were tendered by the early tender date. The tender offer will expire on May 7, 2014, unless extended, and the redemption of the 6.875% Senior Notes due 2018 is expected to occur on May 12, 2014.

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	3 Months Ended
	Mar. 31, 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 are 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.
	This Form 10-Q relates to the three months ended March 31, 2014 (the “Current Quarter”) and the three months ended March 31, 2013 (the “Prior Quarter”). 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 are not necessarily indicative of the results to be expected for the full year.
Risks and Uncertainties [Policy Text Block]	'
	Risks and Uncertainties
	We recently conducted a company-wide review of our operations, assets and organizational structure to best position the Company to maximize shareholder value as we focus on our strategic priorities of financial discipline and profitable and efficient growth from captured resources. We intend to apply financial discipline through all aspects of our business, and we believe that the successful execution of this strategy will allow us to better balance capital expenditures with cash flow from operations as well as reduce financial leverage and complexity. While furthering our strategic priorities, certain actions that would reduce financial leverage and complexity could negatively impact our future results of operations and/or liquidity. We expect to incur various cash and noncash charges, including but not limited to impairments of fixed assets, lease termination charges, financing extinguishment costs and charges for unused natural gas transportation and gathering capacity.

Variable_Interest_Entities_Var

Variable Interest Entities Variable Interest Entity (Policies)	3 Months Ended
	Mar. 31, 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.

Impairment_of_Fixed_Assets_and

Impairment of Fixed Assets and Other (Policies)	3 Months Ended
	Mar. 31, 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.

Recently_Issued_Accounting_Sta1

Recently Issued Accounting Standards Recently Issued Accounting Standards (Policies)	3 Months Ended
	Mar. 31, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements, Policy [Policy Text Block]	'
	In February 2013, the Financial Accounting Standards Board 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 financial statements.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2014
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]	'
	For the Prior Quarter, our cumulative convertible preferred stock and participating securities and associated adjustments to net income, consisting of 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 both the Current Quarter and the Prior Quarter. The following table sets forth the net income adjustments and shares of common stock related to our outstanding cumulative convertible preferred stock and participating securities in the Prior Quarter:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended March 31, 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
	Participating securities	$	—	—
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	A reconciliation of basic EPS and diluted EPS for the Current Quarter is as follows:
		Net Income		Weighted	Per
		Available to		Average	Share
		Common		Shares	Amount
		Stockholders		(Denominator)
		(Numerator)
		(in millions, except per share data)
	Three Months Ended March 31, 2014:
	Basic EPS	$	374	658	$	0.57
	Effect of Dilutive Securities:
	Assumed conversion as of the beginning of the period
	of preferred shares outstanding during the period:
	Common shares assumed issued for 5.75%	21		56
	cumulative convertible preferred stock
	Common shares assumed issued for 5.75%	16		39
	cumulative convertible preferred stock (series A)
	Common shares assumed issued for 5.00%	3		5
	cumulative convertible preferred stock
	(series 2005B)
	Common shares assumed issued for 4.50%	3		6
	cumulative convertible preferred stock
	Outstanding stock options	—		1
	Diluted EPS	$	417	765	$	0.54

Debt_Tables

Debt (Tables)	3 Months Ended
	Mar. 31, 2014
Debt Disclosure [Abstract]	'
Schedule of Debt [Table Text Block]	'
	Our long-term debt consisted of the following as of March 31, 2014 and December 31, 2013:
			March 31,				December 31,
			2014				2013
			($ in millions)
	Term loan due 2017(a)		$	2,000			$	2,000
	9.5% senior notes due 2015(b)		1,265				1,265
	3.25% senior notes due 2016		500				500
	6.25% euro-denominated senior notes due 2017(c)		473				473
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018(d)		97				97
	7.25% senior notes due 2018		669				669
	6.625% senior notes due 2019(e)		650				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
	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		—				—
	Oilfield services revolving bank credit facility		464				405
	Discount on senior notes and term loan(g)		(333		)		(357		)
	Interest rate derivatives(h)		13				13
	Total debt, net		12,969				12,886
	Less current maturities of long-term debt, net(b)		(316		)		—
	Total long-term debt, net		$	12,653			$	12,886
	___________________________________________
	(a)	We repaid the borrowings outstanding under the term loan due 2017 on April 24, 2014 with a portion of the net proceeds from our offering of $3.0 billion in aggregate principal amount of senior notes issued on April 24, 2014. See Note 19 for further discussion of refinancing transactions subsequent to March 31, 2014.
	(b)	On April 10, 2014, we commenced a tender offer for the 9.5% Senior Notes due 2015 concurrently with an offering of senior notes. On April 24, 2014, we purchased approximately $946 million aggregate principal amount of notes that were tendered by the early tender date. The tender offer will expire on May 7, 2014, unless extended. See Note 19 for further discussion of refinancing transactions subsequent to March 31, 2014. The remaining $319 million in aggregate principal amount not tendered by the early tender date and the associated $3 million of discount are reflected as a current liability on our March 31, 2014 condensed consolidated balance sheet.
	(c)	The principal amount shown is based on the exchange rate of $1.3769 to €1.00 and $1.3743 to €1.00 as of March 31, 2014 and December 31, 2013, respectively. See Note 8 for information on our related foreign currency derivatives.
	(d)	On April 10, 2014, we called the 6.875% Senior Notes due 2018 for redemption on May 12, 2014. See Note 19 for discussion of refinancing transactions subsequent to March 31, 2014.
	(e)	Issuers are Chesapeake Oilfield Operating, L.L.C. (COO), an indirect wholly owned subsidiary of the Company, and Chesapeake Oilfield Finance, Inc. (COF), a wholly owned subsidiary of COO formed solely to facilitate the offering of the 6.625% Senior Notes due 2019. COF is nominally capitalized and has no operations or revenues. Chesapeake Energy Corporation is the issuer of all other senior notes and the contingent convertible senior notes.
	(f)	The holders of our contingent convertible senior notes may require us to repurchase, in cash, all or a portion of their notes at 100% of the principal amount of the notes on any of four dates that are five, ten, fifteen and twenty years before the maturity date. The notes are convertible, at the holder’s option, prior to maturity under certain circumstances 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. In the first quarter of 2014, the price of our common stock was below the threshold level for each series of the contingent convertible senior notes during the specified period and, as a result, the holders do not have the option to convert their notes into cash and common stock in the second quarter of 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. Under certain conditions, we will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years. 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. The optional repurchase dates, the common stock price conversion threshold amounts 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		Repurchase Dates		Common Stock				Contingent Interest
	Convertible				Price Conversion				First Payable
	Senior  Notes				Thresholds				(if applicable)
	2.75% due 2035		November 15, 2015, 2020, 2025, 2030		$	48.09			May 14, 2016
	2.5% due 2037		May 15, 2017, 2022, 2027, 2032		$	63.62			November 14, 2017
	2.25% due 2038		December 15, 2018, 2023, 2028, 2033		$	106.75			June 14, 2019
	(g)	Discount as of March 31, 2014 and December 31, 2013 included $284 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 $30 million and $33 million as of March 31, 2014 and December 31, 2013, respectively, associated with our term loan discussed further below.
	(h)	See Note 8 for further discussion related to these instruments.
Schedule of Line of Credit Facilities [Table Text Block]	'
	During the Current Quarter, we had the following two revolving bank credit facilities as sources of liquidity:
			Corporate				Oilfield Services
			Credit Facility(a)				Credit Facility(b)
			($ in millions)
	Facility structure		Senior secured				Senior secured
			revolving				revolving
	Maturity date		December 2015				November 2016
	Borrowing capacity		$	4,000			$	500
	Amount outstanding as of March 31, 2014		$	—			$	464
	Letters of credit outstanding as of March 31, 2014		$	23			$	—
	___________________________________________
	(a)	Co-borrowers are Chesapeake Exploration, L.L.C., Chesapeake Appalachia, L.L.C. and Chesapeake Louisiana, L.P.
	(b)	Borrower is COO.
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.
			31-Mar-14							31-Dec-13
			Carrying				Estimated			Carrying		Estimated
			Amount				Fair Value			Amount		Fair Value
							($ in millions)
	Long-term debt (Level 1)		$	10,522			$	11,639		$	10,501	$	11,557
	Long-term debt (Level 2)		$	2,434			$	2,432		$	2,372	$	2,369

Contingencies_and_Commitments_1

Contingencies and Commitments (Tables)	3 Months Ended
	Mar. 31, 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.
		March 31, 2014
		($ in millions)
	2014	$	1,546
	2015	1,830
	2016	1,915
	2017	1,948
	2018	1,749
	2019 - 2099	7,746
	Total	$	16,734

Other_Liabilities_Other_Liabil

Other Liabilities Other Liabilities (Tables)	3 Months Ended
	Mar. 31, 2014
Other Liabilities Disclosure [Abstract]	'
Other Current Liabilities [Table Text Block]	'
	Other current liabilities as of March 31, 2014 and December 31, 2013 are detailed below.
			March 31,		December 31,
			2014		2013
			($ in millions)
	Revenues and royalties due others		$	1,499	$	1,409
	Accrued natural gas, oil and NGL drilling and production costs		285		457
	Joint interest prepayments received		530		464
	Accrued compensation and benefits		228		320
	Other accrued taxes		113		161
	Accrued dividends		101		101
	Other		538		599
	Total other current liabilities		$	3,294	$	3,511
Other Long-Term Liabilities [Table Text Block]	'
	Other long-term liabilities as of March 31, 2014 and December 31, 2013 are detailed below.
			March 31,		December 31,
			2014		2013
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	242	$	250
	CHK C-T ORRI conveyance obligation(b)		146		149
	Financing obligations		30		31
	Other		433		554
	Total other long-term liabilities		$	851	$	984
	____________________________________________
	(a)	$15 million and $13 million of the total $257 million and $263 million obligations are recorded in other current liabilities as of March 31, 2014 and December 31, 2013, respectively. See Note 6 for further discussion of the transaction.
	(b)	$15 million and $12 million of the total $161 million and $161 million obligations are recorded in other current liabilities as of March 31, 2014 and December 31, 2013, respectively. See Note 6 for further discussion of the transaction.

Equity_Tables

Equity (Tables)	3 Months Ended
	Mar. 31, 2014
Equity [Abstract]	'
Common Stock [Table Text Block]	'
	The following is a summary of the changes in our common shares issued for the three months ended March 31, 2014 and 2013:
			Three Months Ended
			March 31,
			2014			2013
			(in thousands)
	Shares issued as of January 1		666,192			666,468
	Restricted stock issuances (net of forfeitures)(a)		(1,236	)		2,631
	Stock option exercises		259			176
	Shares issued as of March 31		665,215			669,275
	___________________________________________
	(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 and liquidation preferences of our cumulative convertible preferred stock for the three months ended March 31, 2014 and 2013:
			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
	March 31, 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 Quarter and the Prior Quarter, 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		11				(5		)		6
	Net other comprehensive income		14				(5		)		9
	Balance, March 31, 2014		$	(153	)		$	—			$	(153	)
			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		(1		)		(5		)		(6		)
	Amounts reclassified from accumulated other comprehensive income		12				6				18
	Net other comprehensive income		11				1				12
	Balance, March 31, 2013		$	(178	)		$	8			$	(170	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Three Months Ended
			March 31,
			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		4				3				(2		)	(1		)
	Losses reclassified to income		18				11				19			12
	Balance, end of period		$	(247	)		$	(153	)		$	(287	)	$	(178	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	'
	For the Current Quarter and the Prior Quarter, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed consolidated statements of operations are detailed below.
	Details About Accumulated		Affected Line Item		Three Months Ended
	Other Comprehensive		in the Statement		March 31,
	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		$	11			$	12
	Investments:
	Impairment of investment		Losses on investments		—				6
	Sale of investment		Net gain on sale of investment		(5		)		—
	Total reclassifications for the period, net of tax				$	6			$	18
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	For the Current Quarter and the Prior Quarter, the Trust declared and paid the following distributions:
	Production Period		Distribution Date		Cash Distribution				Cash Distribution
					per				per
					Common Unit				Subordinated Unit
	September 2013 - November 2013		March 3, 2014		$	0.6624			$	—
	September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation [Table Text Block]	'
	We recorded the following compensation expenses related to restricted stock and stock options during the Current Quarter and the Prior Quarter:
			Three Months Ended
			March 31,
			2014				2013
			($ in millions)
	General and administrative expenses		$	12			$	20
	Natural gas and oil properties		7				21
	Natural gas, oil and NGL production expenses		4				6
	Marketing, gathering and compression expenses		2				3
	Oilfield services expenses		2				3
	Total		$	27			$	53
Schedule of Unvested Restricted Stock Units Roll Forward [Table Text Block] [Table Text Block]	'
	A summary of the changes in unvested shares of restricted stock during the Current Quarter 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		3,943			$	25.13
	Vested		(2,350	)		$	26.41
	Forfeited		(638	)		$	25.69
	Unvested shares as of March 31, 2014		14,355			$	23.26
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	'
	The Company used the following assumptions to estimate the grant date fair value of the stock options granted in the Current Quarter:
	Expected option life - years		6
	Volatility		48.33	%
	Risk-free interest rate		1.97	%
	Dividend yield		1.36	%
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	'
	The following table provides information related to stock option activity during the Current Quarter:
			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		786			$	25.71
	Exercised		(270	)		$	18.23				$	2
	Expired		—			$	—
	Outstanding at March 31, 2014		5,784			$	20.2		7.15		$	31
	Exercisable at March 31, 2014		1,766			$	18.95		3.72		$	12
	___________________________________________
	(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.
Schedule of Nonvested Performance-based Units Activity [Table Text Block]	'
	The following table presents a summary of our PSU awards as of March 31, 2014:
			Units			Fair Value			Fair Value				Liability for
						as of							Vested
						Grant Date							Amount
						($ in millions)
	2012 Awards (a)
	Payable 2015		834,248			$	23		$	21			$	21
	2013 Awards
	Payable 2016		1,600,438			$	35		$	52			$	45
	2014 Awards
	Payable 2017		620,669			$	17		$	16			$	4
	___________________________________________
	(a)	In the Current Quarter and the Prior Quarter, we paid $11 million and $2 million, respectively, related to 2012 PSU awards.
Schedule of Share-based Compensation, PSU Units, Activity [Table Text Block]	'
	We recorded the following compensation expenses related to PSUs during the Current Quarter and the Prior Quarter:
			Three Months Ended
			March 31,
			2014				2013
			($ in millions)
	Natural gas and oil properties		$	1			$	4
	General and administrative expenses		(1		)		5
	Marketing, gathering and compression expenses		—				2
	Total		$	—			$	11

Derivative_and_Hedging_Activit1

Derivative and Hedging Activities (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2014 and December 31, 2013 are provided below.
			31-Mar-14							31-Dec-13
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		394			$	(125	)		448			$	(23	)
	Three-way collars		387			(48		)		288			(7		)
	Call options		193			(202		)		193			(210		)
	Call swaptions		—			—				12			—
	Basis protection swaps		151			(14		)		68			3
	Total natural gas		1,125			(389		)		1,009			(237		)
	Oil (mmbbl):
	Fixed-price swaps		22.8			(81		)		25.3			(50		)
	Call options		41.9			(257		)		42.5			(265		)
	Basis protection swaps		0.3			1				0.4			1
	Total oil		65			(337		)		68.2			(314		)
	Total estimated fair value					$	(726	)					$	(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 March 31, 2014 and December 31, 2013 on a gross basis and after same-counterparty netting:
			March 31, 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		$	13			$	(11	)		$	2
	Long-term derivative asset		3				1				4
	Short-term derivative liability		(425		)		11				(414		)
	Long-term derivative liability		(317		)		(1		)		(318		)
	Total commodity contracts		(726		)		—				(726		)
	Interest Rate Contracts
	Short-term derivative liability		(3		)		—				(3		)
	Long-term derivative liability		(77		)		—				(77		)
	Total interest rate contracts		(80		)		—				(80		)
	Foreign Currency Contracts(a)
	Long-term derivative asset		7				—				7
	Total foreign currency contracts		7				—				7
	Total Derivatives		$	(799	)		$	—			$	(799	)
			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 and the Prior Quarter are presented below.
			Three Months Ended
			March 31,
			2014				2013
			($ in millions)
	Natural gas, oil and NGL sales		$	2,148			$	1,595
	Losses on undesignated natural gas, oil and NGL derivatives		(365		)		(123		)
	Losses on terminated cash flow hedges		(17		)		(19		)
	Total natural gas, oil and NGL sales		$	1,766			$	1,453
Interest Income And Interest Expense Disclosure [Table Text Block]	'
	The components of interest expense for the Current Quarter and the Prior Quarter are presented below.
			Three Months Ended
			March 31,
			2014				2013
			($ in millions)
	Interest expense on senior notes		$	180			$	186
	Interest expense on term loans		29				29
	Amortization of loan discount, issuance costs and other		19				19
	Interest expense on credit facilities		8				12
	Gains on terminated fair value hedges		(1		)		—
	(Gains) losses on undesignated interest rate derivatives		(18		)		4
	Capitalized interest		(178		)		(229		)
	Total interest expense		$	39			$	21
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	For the Current Quarter and the Prior Quarter, 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		11				(5		)		6
	Net other comprehensive income		14				(5		)		9
	Balance, March 31, 2014		$	(153	)		$	—			$	(153	)
			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		(1		)		(5		)		(6		)
	Amounts reclassified from accumulated other comprehensive income		12				6				18
	Net other comprehensive income		11				1				12
	Balance, March 31, 2013		$	(178	)		$	8			$	(170	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Three Months Ended
			March 31,
			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		4				3				(2		)		(1		)
	Losses reclassified to income		18				11				19				12
	Balance, end of period		$	(247	)		$	(153	)		$	(287	)		$	(178	)
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 March 31, 2014 and December 31, 2013:
	As of March 31, 2014		Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	Derivative Assets (Liabilities):
	Commodity assets		$	—			$	10			$	6			$	16
	Commodity liabilities		—				(229		)		(513		)		(742		)
	Interest rate liabilities		—				(80		)		—				(80		)
	Foreign currency assets		—				7				—				7
	Total derivatives		$	—			$	(292	)		$	(507	)		$	(799	)
	As of 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)
	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 financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2014 and December 31, 2013:
	As of March 31, 2014		Quoted				Significant				Significant				Total
			Prices in				Other				Unobservable				Fair Value
			Active				Observable				Inputs
			Markets				Inputs				(Level 3)
			(Level 1)				(Level 2)
							($ in millions)
	Financial Assets (Liabilities):
	Other current assets		$	78			$	—			$	—			$	78
	Other current liabilities		(80		)		—				—				(80		)
	Total		$	(2	)		$	—			$	—			$	(2	)
	As of 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)
	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 Quarter and the Prior Quarter 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)		(80		)		—
	Total purchases, issuances, sales and settlements:
	Settlements		55				—
	Transfers(b)		(4		)		—
	Ending Balance as of March 31, 2014		$	(507	)		$	—
	Beginning Balance as of January 1, 2013		$	(1,016	)		$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		194				(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—				(1		)
	Settlements		37				—
	Ending Balance as of March 31, 2013		$	(785	)		$	(2	)
	___________________________________________
	(a)		Natural Gas, Oil and								Interest Expense
			NGL Sales
			2014				2013				2014				2013
			($ in millions)
	Total gains (losses) included in earnings for the		$	(80	)		$	194			$	—			$	(1	)
	period
	Change in unrealized gains (losses) related to		$	(57	)		$	191			$	—			$	(2	)
	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]	'
	Qualitative 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.
	Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
	Instrument		Unobservable		Range		Weighted			Fair Value
	Type		Input				Average			March 31, 2014(a)
										($ in millions)
	Oil trades		Oil price volatility curves		10.56% - 21.78%		15.43	%		$	(256	)
	Natural gas trades		Natural gas price volatility		18.03% - 38.37%		24.32	%		$	(251	)
			curves
	___________________________________________
	(a)	Fair value is based on an estimate derived from option models.

Natural_Gas_and_Oil_Property_D1

Natural Gas and Oil Property Divestitures (Tables)	3 Months Ended
	Mar. 31, 2014
Business Combinations [Abstract]	'
Drilling And Completion Costs Associated To Joint Ventures [Table Text Block]	'
	For accounting purposes, initial cash proceeds from these joint venture transactions were reflected as a reduction of natural gas and oil properties with no gain or loss recognized. The transactions are detailed below.
	Primary		Joint	Joint		Interest		Initial Proceeds(b)				Total				Total Initial			Drilling
	Play		Venture	Venture		Sold						Drilling				Proceeds			Carries
			Partner(a)	Date								Carries				and Drilling			Remaining(c)
																Carries
								($ in millions)
	Mississippi Lime		Sinopec	Jun-13		50.00%		$	949		(d)	$	—			$	949		$	—
	Utica		TOT	December 2011		25.00%		610				1,422			(e)	2,032			478
	Niobrara		CNOOC	Feb-11		33.30%		570				697			(f)	1,267			64
	Eagle Ford		CNOOC	Nov-10		33.30%		1,120				1,080				2,200			—
	Barnett		TOT	Jan-10		25.00%		800				1,403				2,203			—
	Marcellus		STO	Nov-08		32.50%		1,250				2,125				3,375			—
	Fayetteville		BP	September 2008		25.00%		1,100				800				1,900			—
	Haynesville & Bossier		FCX	Jul-08		20.00%		1,650				1,508				3,158			—
								$	8,049			$	9,035			$	17,084		$	542
	____________________________________________
	(a)	Joint venture partners are Sinopec International Petroleum Exploration and Production (Sinopec), Total S.A. (TOT), CNOOC Limited (CNOOC), Statoil (STO), BP America (BP) and Freeport-McMoRan Copper & Gold (FCX), formerly known as Plains Exploration & Production Company.
	(b)	Excludes closing and post-closing adjustments.
	(c)	As of March 31, 2014.
	(d)	Excludes $71 million of net proceeds (or 7% of the total transaction) expected to be received pursuant to certain post-closing adjustments and approximately $90 million received at closing for closing adjustments.
	(e)	The Utica drilling carry covers 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize this drilling carry commitment prior to expiration. See Note 4 for further discussion of the Utica drilling carries.
	(f)	The Niobrara drilling carry covers 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize this drilling carry commitment prior to expiration.
VPP Transactions [Table Text Block]	'
	Our outstanding VPPs consist of the following:
										Volume Sold
	VPP #		Date of VPP	Location		Proceeds				Natural Gas			Oil			NGL		Total
						($ 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
	5		Aug-09	South Texas		370				67			0.2			—		68
	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
						$	6,031			1,216			5.7			14		1,334
VPP Volumes Produced During Period [Table Text Block]	'
	The volumes produced on behalf of our VPP buyers for the Current Quarter and the Prior Quarter were as follows:
			Three Months Ended March 31, 2014											Three Months Ended March 31, 2013
	VPP #		Natural Gas		Oil			NGL			Total			Natural Gas			Oil		NGL		Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)			(bcf)			(mbbl)		(mbbl)		(bcfe)
	10		2.8		109			345.2			5.5			3.7			154		407.7		6.9
	9		4		49			106.5			4.9			4.4			56.2		118.8		5.5
	8		15.7		—			—			15.7			18			—		—		18
	6		1.1		6			—			1.2			1.2			6		—		1.2
	5		1.7		6.3			—			1.8			2			6		—		2
	4		2.3		12.4			—			2.4			2.6			14.2		—		2.7
	3		1.9		—			—			1.9			2.1			—		—		2.1
	2		2.4		—			—			2.4			2.7			—		—		2.7
	1		3.6		—			—			3.6			3.8			—		—		3.8
			35.5		182.7			451.7			39.4			40.5			236.4		526.5		44.9
VPP Volumes Remaining to be Delivered [Table Text Block]	'
	The volumes remaining to be delivered on behalf of our VPP buyers as of March 31, 2014 were as follows:
				Volume Remaining as of March 31, 2014
	VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
			(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
	10		95	45.8			1.6			5.6			89.2
	9		83	84.7			1			2.2			104
	8		17	80.9			—			—			80.9
	6		70	20.3			0.1			—			21.1
	5		34	15.2			0.1			—			15.5
	4		33	22			0.1			—			22.7
	3		64	29.2			—			—			29.2
	2		61	17.6			—			—			17.6
	1		105	101.8			—			—			101.8
				417.5			2.9			7.8			482

Investments_Tables

Investments (Tables)	3 Months Ended
	Mar. 31, 2014
Investments [Abstract]	'
Investment Holdings, Schedule of Investments [Table Text Block]	'
	A summary of our investments, including our approximate ownership percentage as of March 31, 2014 and December 31, 2013, is presented below.
			Approximate		Carrying
			Ownership %		Value
		Accounting	March 31,	December 31,	March 31,		December 31,
		Method	2014	2013	2014		2013
					($ in millions)
	FTS International, Inc.	Equity	30%	30%	$	129	$	138
	Chaparral Energy, Inc.	Equity	—%	20%	—		143
	Sundrop Fuels, Inc.	Equity	56%	56%	134		135
	Other	—	—%	—%	25		61
	Total investments				$	288	$	477

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	3 Months Ended
	Mar. 31, 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 and the Prior Quarter is as follows:
		Three Months Ended
		March 31,
		2014			2013
		($ in millions)
	Natural gas compressors	$	(26	)	$	—
	Gathering systems and treating plants	3			(69		)
	Drilling rigs and equipment	2			1
	Buildings and land	—			22
	Other	(2		)	(3		)
	Total net gains on sales of fixed assets	$	(23	)	$	(49	)
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 March 31, 2014 and December 31, 2013 is detailed below.
		March 31,			December 31,
		2014			2013
		($ in millions)
	Natural gas gathering systems and treating plants, net of accumulated depreciation	$	10		$	11
	Oilfield services equipment, net of accumulated depreciation	58			29
	Compressors, net of accumulated depreciation	322			285
	Buildings and land, net of accumulated depreciation	237			405
	Property and equipment held for sale, net	$	627		$	730

Impairments_of_Fixed_Assets_an1

Impairments of Fixed Assets and Other (Tables)	3 Months Ended
	Mar. 31, 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 and the Prior Quarter is as follows:
		Three Months Ended
		March 31,
		2014		2013
		($ in millions)
	Drilling rigs and equipment	$	20	$	—
	Buildings and land	—		27
	Total impairments of fixed assets and other	$	20	$	27

Recovered_Sheet1

Restructuring and other Termination Benefits (Tables)	3 Months Ended
	Mar. 31, 2014
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Costs [Table Text Block]	'
	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 and the Prior Quarter:
			Three Months Ended
			March 31,
			2014			2013
			($ in millions)
	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)		(4		)	13
	Estimated aircraft usage benefits		—			7
	Total termination benefits provided to Mr. McClendon		(4		)	64
	Termination benefits provided to VSP participants:
	Salary and bonus expense		—			30
	Acceleration of stock-based compensation		—			24
	Other termination benefits		—			2
	Total termination benefits provided to VSP participants		—			56
	Other termination benefits(a)		(3		)	13
	Total restructuring and other termination costs		$	(7	)	$	133
	____________________________________________
	(a)	The Current Quarter amount primarily related to negative fair value adjustments to PSUs granted to former executives of the Company. For further discussion of our PSUs, see Note 7.

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 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 March 31, 2014 and December 31, 2013:
	As of March 31, 2014	Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	Derivative Assets (Liabilities):
	Commodity assets	$	—		$	10		$	6		$	16
	Commodity liabilities	—			(229		)	(513		)	(742		)
	Interest rate liabilities	—			(80		)	—			(80		)
	Foreign currency assets	—			7			—			7
	Total derivatives	$	—		$	(292	)	$	(507	)	$	(799	)
	As of 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)
	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 financial assets (liabilities) measured at fair value on a recurring basis as of March 31, 2014 and December 31, 2013:
	As of March 31, 2014	Quoted			Significant			Significant			Total
		Prices in			Other			Unobservable			Fair Value
		Active			Observable			Inputs
		Markets			Inputs			(Level 3)
		(Level 1)			(Level 2)
					($ in millions)
	Financial Assets (Liabilities):
	Other current assets	$	78		$	—		$	—		$	78
	Other current liabilities	(80		)	—			—			(80		)
	Total	$	(2	)	$	—		$	—		$	(2	)
	As of 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)
	Financial Assets (Liabilities):
	Other current assets	$	80		$	—		$	—		$	80
	Other current liabilities	(82		)	—			—			(82		)
	Total	$	(2	)	$	—		$	—		$	(2	)

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 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,			Oilfield			Other			Intercompany			Consolidated
		and		Gathering			Services						Eliminations			Total
		Production		and
				Compression
		($ in millions)
	Three Months Ended March 31, 2014:
	Revenues	$	1,766	$	5,423		$	510		$	26		$	(2,679	)	$	5,046
	Intersegment revenues	—		(2,408		)	(271		)	—			2,679			—
	Total revenues	$	1,766	$	3,015		$	239		$	26		$	—		$	5,046
	Income (Loss) Before	$	687	$	105		$	(42	)	$	60		$	(64	)	$	746
	Income Taxes
	Three Months Ended March 31, 2013:
	Revenues	$	1,453	$	3,529		$	538		$	10		$	(2,106	)	$	3,424
	Intersegment revenues	—		(1,748		)	(352		)	(6		)	2,106			—
	Total revenues	$	1,453	$	1,781		$	186		$	4		$	—		$	3,424
	Income (Loss) Before	$	170	$	129		$	22		$	(58	)	$	(98	)	$	165
	Income Taxes
	As of
	March 31, 2014:
	Total Assets	$	36,102	$	2,950		$	2,058		$	5,516		$	(4,021	)	$	42,605
	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)	3 Months Ended
	Mar. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule of Condensed Balance Sheet [Table Text Block]	'
	CONSOLIDATING BALANCE SHEET
	AS OF MARCH 31, 2014
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	974		$	—		$	75		$	(45	)	$	1,004
	Restricted cash		—			—			82			(7		)	75
	Other		88			2,862			623			(377		)	3,196
	Intercompany receivable, net		25,431			—			—			(25,431		)	—
	Total Current Assets		26,493			2,862			780			(25,860		)	4,275
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,891			3,075			(94		)	32,872
	Other property and equipment, net		—			2,523			1,501			(1		)	4,023
	Property and equipment held for		—			569			58			—			627
	sale, net
	Total Property and Equipment,		—			32,983			4,634			(95		)	37,522
	Net
	LONG-TERM ASSETS:
	Other assets		109			962			109			(372		)	808
	Investments in subsidiaries and		2,387			(201		)	—			(2,186		)	—
	intercompany advances
	TOTAL ASSETS		$	28,989		$	36,606		$	5,523		$	(28,513	)	$	42,605
	CURRENT LIABILITIES:
	Current liabilities		$	550		$	5,445		$	392		$	(429	)	$	5,958
	Intercompany payable, net		—			24,922			257			(25,179		)	—
	Total Current Liabilities		550			30,367			649			(25,608		)	5,958
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,539			—			1,114			—			12,653
	Deferred income tax liabilities		293			2,834			1,117			(416		)	3,828
	Other long-term liabilities		266			1,018			777			(372		)	1,689
	Total Long-Term Liabilities		12,098			3,852			3,008			(788		)	18,170
	EQUITY:
	Chesapeake stockholders’ equity		16,341			2,387			1,866			(4,253		)	16,341
	Noncontrolling interests		—			—			—			2,136			2,136
	Total Equity		16,341			2,387			1,866			(2,117		)	18,477
	TOTAL LIABILITIES AND EQUITY		$	28,989		$	36,606		$	5,523		$	(28,513	)	$	42,605
	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			2,392			616			(367		)	2,744
	Intercompany receivable, net		25,369			—			—			(25,369		)	—
	Total Current Assets		26,271			2,392			737			(25,744		)	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		—			2,315			1,497			(1		)	3,811
	Property and equipment held for		—			701			29			—			730
	sale, net
	Total Property and Equipment,		—			32,311			4,639			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,146			111			(376		)	992
	Investments in subsidiaries and		2,349			(251		)	—			(2,098		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,598		$	5,487		$	(28,034	)	$	41,782
	CURRENT LIABILITIES:
	Current liabilities		$	300		$	5,211		$	379		$	(375	)	$	5,515
	Intercompany payable, net		—			24,752			593			(25,345		)	—
Total Current Liabilities		300			29,963			972			(25,720		)	5,515
LONG-TERM LIABILITIES:
Long-term debt, net		11,831			—			1,055			—			12,886
Deferred income tax liabilities		209			2,264			847			87			3,407
Other liabilities		396			1,022			788			(372		)	1,834
Total Long-Term Liabilities		12,436			3,286			2,690			(285		)	18,127
EQUITY:
Chesapeake stockholders’ equity		15,995			2,349			1,825			(4,174		)	15,995
Noncontrolling interests		—			—			—			2,145			2,145
Total Equity		15,995			2,349			1,825			(2,029		)	18,140
TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,598		$	5,487		$	(28,034	)	$	41,782
Schedule of Condensed Income Statement [Table Text Block]	'
	CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED MARCH 31, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	1,545		$	222		$	(1	)	$	1,766
	Marketing, gathering and compression		—			3,014			1			—			3,015
	Oilfield services		—			—			536			(271		)	265
	Total Revenues		—			4,559			759			(272		)	5,046
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			269			19			—			288
	Production taxes		—			49			1			—			50
	Marketing, gathering and compression		—			2,979			1			—			2,980
	Oilfield services		—			17			437			(234		)	220
	General and administrative		—			53			26			—			79
	Restructuring and other termination costs		—			(7		)	—			—			(7		)
	Natural gas, oil and NGL depreciation,		—			568			62			(2		)	628
	depletion and amortization
	Depreciation and amortization of other		—			39			74			(35		)	78
	assets
	Impairment of natural gas and oil properties		—			—			59			(59		)	—
	Impairments of fixed assets and other		—			—			20			—			20
	Net gains on sales of fixed assets		—			(24		)	1			—			(23		)
	Total Operating Expenses		—			3,943			700			(330		)	4,313
	INCOME FROM OPERATIONS		—			616			59			58			733
	OTHER INCOME (EXPENSE):
	Interest expense		(192		)	—			(21		)	174			(39		)
	Losses on investments		—			(15		)	—			(6		)	(21		)
	Gain on sale of investment		—			67			—			—			67
	Other income (loss)		344			(141		)	1			(198		)	6
	Equity in net earnings of subsidiary		330			(17		)	—			(313		)	—
	Total Other Income (Expense)		482			(106		)	(20		)	(343		)	13
	INCOME BEFORE INCOME TAXES		482			510			39			(285		)	746
	INCOME TAX EXPENSE		57			198			15			10			280
	NET INCOME		425			312			24			(295		)	466
	Net income attributable to		—			—			—			(41		)	(41		)
	noncontrolling interests
	NET INCOME ATTRIBUTABLE		425			312			24			(336		)	425
	TO CHESAPEAKE
	Other comprehensive income		2			7			—			—			9
	COMPREHENSIVE INCOME		$	427		$	319		$	24		$	(336	)	$	434
	ATTRIBUTABLE TO CHESAPEAKE
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED MARCH 31, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	1,322		$	128		$	3		$	1,453
	Marketing, gathering and compression		—			1,778			3			—			1,781
	Oilfield services		—			—			554			(364		)	190
	Total Revenues		—			3,100			685			(361		)	3,424
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			296			11			—			307
	Production taxes		—			51			2			—			53
	Marketing, gathering and compression		—			1,742			3			—			1,745
	Oilfield services		—			23			426			(294		)	155
	General and administrative		—			87			23			—			110
	Restructuring and other termination costs		—			131			2			—			133
	Natural gas, oil and NGL depreciation,		—			591			57			—			648
depletion and amortization
Depreciation and amortization of other		—			48			71			(41		)	78
assets
Impairment of natural gas and oil		—			—			91			(91		)	—
properties
Impairments of fixed assets and other		—			27			—			—			27
Net gains on sales of fixed assets		—			(49		)	—			—			(49		)
Total Operating Expenses		—			2,947			686			(426		)	3,207
INCOME FROM OPERATIONS		—			153			(1		)	65			217
OTHER INCOME (EXPENSE):
Interest expense		(219		)	(8		)	(16		)	222			(21		)
Losses on investments		—			(37		)	—			—			(37		)
Other income		216			42			(2		)	(250		)	6
Equity in net earnings (losses) of		60			(87		)	—			27			—
subsidiary
Total Other Income (Expense)		57			(90		)	(18		)	(1		)	(52		)
INCOME (LOSS) BEFORE INCOME TAXES		57			63			(19		)	64			165
INCOME TAX EXPENSE (BENEFIT)		(1		)	57			(7		)	14			63
NET INCOME (LOSS)		58			6			(12		)	50			102
Net income attributable to		—			—			—			(44		)	(44		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		58			6			(12		)	6			58
TO CHESAPEAKE
Other comprehensive income (loss)		(2		)	14			—			—			12
COMPREHENSIVE INCOME (LOSS)		$	56		$	20		$	(12	)	$	6		$	70
ATTRIBUTABLE TO CHESAPEAKE
Schedule of Condensed Cash Flow Statement [Table Text Block]	'
	CONSOLIDATING STATEMENT OF CASH FLOWS
	THREE MONTHS ENDED MARCH 31, 2014
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	1,027		$	264		$	—		$	1,291
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Acquisitions of proved and unproved		—			(956		)	(128		)	—			(1,084		)
	properties
	Proceeds from divestitures of proved		—			48			1			—			49
	and unproved properties
	Additions to other property and		—			(319		)	(118		)	—			(437		)
	equipment
	Other investing activities		—			442			5			26			473
	Net Cash Used In Investing		—			(785		)	(240		)	26			(999		)
	Activities
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities		—			140			281			—			421
	borrowings
	Payments on credit facilities borrowings		—			(140		)	(222		)	—			(362		)
	Other financing activities		(116		)	47			(45		)	(70		)	(184		)
	Intercompany advances, net		291			(289		)	(2		)	—			—
	Net Cash Provided By (Used In)		175			(242		)	12			(70		)	(125		)
	Financing Activities
	Net increase (decrease) in cash and cash		175			—			36			(44		)	167
	equivalents
	Cash and cash equivalents, beginning of		799			—			39			(1		)	837
	period
	Cash and cash equivalents, end of period		$	974		$	—		$	75		$	(45	)	$	1,004
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	THREE MONTHS ENDED MARCH 31, 2013
	($ in millions)
			Parent(a)			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	790		$	146		$	(12	)	$	924
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Acquisitions of proved and unproved		—			(1,643		)	(216		)	—			(1,859		)
	properties
	Proceeds from divestitures of proved		—			138			52			—			190
	and unproved properties
	Additions to other property and		—			(186		)	(144		)	—			(330		)
	equipment
	Other investing activities		—			135			74			45			254
	Net Cash Used In Investing		—			(1,556		)	(234		)	45			(1,745		)
	Activities
	CASH FLOWS FROM FINANCING
	ACTIVITIES:
	Proceeds from credit facilities		—			3,395			237			—			3,632
	borrowings
	Payments on credit facilities		—			(2,563		)	(248		)	—			(2,811		)
	borrowings
	Other financing activities		(133		)	(94		)	6			(33		)	(254		)
	Intercompany advances, net		(95		)	28			67			—			—
	Net Cash Provided By (Used		(228		)	766			62			(33		)	567
	In) Financing Activities
	Net increase in cash and cash equivalents		(228		)	—			(26		)	—			(254		)
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	—		$	—		$	33		$	—		$	33
___________________________________________
(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 of $228 million, which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

Earnings_Per_Share_Antidilutiv

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Earnings Per Share, Basic	$0.57	$0.02
Diluted	$0.54	$0.02
Weighted Average Number of Shares Outstanding, Basic	658	651
Weighted Average Number of Shares Outstanding, Diluted	765	651
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Net Income Adjustments	'	$21
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	56
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock Series A	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Net Income Adjustments	'	16
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	39
Convertible Debt Securities [Member] | 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
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	5
Convertible Debt Securities [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Net Income Adjustments	'	3
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	6
Restricted stock	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'
Net Income Adjustments	'	$0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	'	0

Earnings_Per_Share_Earnings_Pe

Earnings Per Share Earnings Per Share - Basic and Diluted Table (Details) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Earnings Per Share Disclosure [Line Items]	'	'
Net Income (Loss) Available to Common Stockholders, Basic	$374	$15
Weighted Average Number of Shares Outstanding, Basic	658	651
Earnings Per Share, Basic	$0.57	$0.02
Net Income (Loss) Attributable to Parent	417	'
Weighted Average Number of Shares Outstanding, Diluted	765	651
Diluted	$0.54	$0.02
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock	'	'
Earnings Per Share Disclosure [Line Items]	'	'
Dilutive Securities, Effect on Basic Earnings Per Share	21	'
Weighted Average Number Diluted Shares Outstanding Adjustment	56	'
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock Series A	'	'
Earnings Per Share Disclosure [Line Items]	'	'
Dilutive Securities, Effect on Basic Earnings Per Share	16	'
Weighted Average Number Diluted Shares Outstanding Adjustment	39	'
Convertible Debt Securities [Member] | 5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'	'
Earnings Per Share Disclosure [Line Items]	'	'
Dilutive Securities, Effect on Basic Earnings Per Share	3	'
Weighted Average Number Diluted Shares Outstanding Adjustment	5	'
Convertible Debt Securities [Member] | 4.50% Cumulative Convertible Preferred Stock [Member]	'	'
Earnings Per Share Disclosure [Line Items]	'	'
Dilutive Securities, Effect on Basic Earnings Per Share	3	'
Weighted Average Number Diluted Shares Outstanding Adjustment	6	'
Stock Options	'	'
Earnings Per Share Disclosure [Line Items]	'	'
Weighted Average Number Diluted Shares Outstanding Adjustment	1	'
Amount of Dilutive Securities, Stock Options	$0	'

Debt_LongTerm_Debt_Table_Detai

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

3 Months Ended

3 Months Ended

0 Months Ended

0 Months Ended

In Millions, except Per Share data, unless otherwise specified

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Apr. 25, 2014

Apr. 24, 2014

Apr. 25, 2014

Apr. 24, 2014

Apr. 10, 2014

Mar. 31, 2014

Corporate Revolving Bank Credit Facility

Corporate Revolving Bank Credit Facility

Oilfield Services Revolving Bank Credit Facility

Oilfield Services Revolving Bank Credit Facility

Interest rate contract

Interest rate contract

6.875% Senior Notes Due 2018

2.75% Contingent Convertible Senior Notes Due 2035

2.5% Contingent Convertible Senior Notes due 2037

2.25% Contingent Convertible Senior Notes Due 2038

Term Loan [Member]

Term Loan [Member]

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Note Discounts [Member]

Note Discounts [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Senior Secured Term Loan Due 2017

Senior Secured Term Loan Due 2017

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

3.25% Senior Notes due 2016

3.25% Senior Notes due 2016

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.5% Senior Notes Due 2017

6.5% Senior Notes Due 2017

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

7.25% Senior Notes Due 2018

7.25% Senior Notes Due 2018

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2020

6.625% Senior Notes Due 2020

6.875% Senior Notes Due 2020

6.875% Senior Notes Due 2020

6.125% Senior Notes Due 2021

6.125% Senior Notes Due 2021

5.375% Senior Notes due 2021

5.375% Senior Notes due 2021

5.75% Senior Notes due 2023

5.75% Senior Notes due 2023

2.75% Contingent Convertible Senior Notes Due 2035

2.75% Contingent Convertible Senior Notes Due 2035

2.5% Contingent Convertible Senior Notes due 2037

2.5% Contingent Convertible Senior Notes due 2037

2.25% Contingent Convertible Senior Notes Due 2038

2.25% Contingent Convertible Senior Notes Due 2038

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

6.875% Senior Notes Due 2018

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

$12,969

$12,886

$0

$0

$464

$405

$13

$13

'

'

'

'

$2,000

$2,000

'

'

$1,265

$1,265

$500

$500

$473

$473

$473

'

$660

$660

$97

$97

$669

$669

$650

$650

$1,300

$1,300

$500

$500

$1,000

$1,000

$700

$700

$1,100

$1,100

$396

$396

$1,168

$1,168

$347

$347

'

'

'

$3,000

'

$319

'

'

Current maturities of long-term debt, net

-316

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Notes Payable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

946

'

946

'

'

'

Long-term Debt, Excluding Current Maturities

12,653

12,886

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Discount

'

'

'

'

'

'

'

'

'

'

'

'

$30

$33

$284

$303

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($333)

($357)

'

'

'

$3

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3769

1.3743

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

6.63%

'

'

'

'

'

'

'

9.50%

'

3.25%

'

'

'

6.25%

'

6.50%

'

6.88%

'

7.25%

'

6.63%

'

6.63%

'

6.88%

'

6.13%

'

5.38%

'

5.75%

'

2.75%

'

2.50%

'

2.25%

'

'

'

'

'

'

'

9.50%

6.88%

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

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Convertible, Terms of Conversion Feature

'5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock Price Conversion Thresholds

'

'

'

'

'

'

'

'

'

$48.09

$63.62

$106.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Date of First Required Payment

'

'

'

'

'

'

'

'

'

14-May-16

14-Nov-17

14-Jun-19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Long_Term_Debt_Table_Phan

Debt - Long Term Debt Table (Phantom) (Details)	3 Months Ended
	Mar. 31, 2014
Senior Secured Term Loan Due 2017 | Term Loan [Member]	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument Maturity Year	'2017
9.5% Senior Notes Due 2015 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument Maturity Year	'2015
3.25% Senior Notes due 2016 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument Maturity Year	'2016
6.25% Euro-Denominated Senior Notes Due 2017 | Senior Notes | Cross Currency Interest Rate Contract [Member]	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.25%
Debt Instrument Maturity Year	'2017
6.5% Senior Notes Due 2017 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Year	'2017
6.875% Senior Notes Due 2018	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
6.875% Senior Notes Due 2018 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument Maturity Year	'2018
7.25% Senior Notes Due 2018 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Year	'2018
6.625% Senior Notes Due 2019 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Year	'2019
6.625% Senior Notes Due 2020 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Year	'2020
6.875% Senior Notes Due 2020 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument Maturity Year	'2020
5.375% Senior Notes due 2021 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.38%
Debt Instrument Maturity Year	'2021
6.125% Senior Notes Due 2021 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument Maturity Year	'2021
5.75% Senior Notes due 2023 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument Maturity Year	'2023
2.75% Contingent Convertible Senior Notes Due 2035	'
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 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument Maturity Year	'2035
2.5% Contingent Convertible Senior Notes due 2037	'
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 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument Maturity Year	'2037
2.25% Contingent Convertible Senior Notes Due 2038	'
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 | Senior Notes	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument Maturity Year	'2038

Debt_Term_Loans_Narrative_Deta

Debt - Term Loans Narrative (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Nov. 07, 2012	Mar. 31, 2014	Dec. 31, 2013	Apr. 24, 2014
			Term Loan [Member]	Term Loan [Member]	Senior Notes	Senior Notes	Senior Notes
Long-Term Debt Instrument [Line Items]	'	'	'	'	'	'	'
Credit Facility Commitment Period	'	'	'five-year	'	'	'	'
Unsecured Debt	'	'	'	$2,000,000,000	'	'	'
Net proceeds from issuance of unsecured loan	'	'	1,935,000,000	'	'	'	'
Long-term Debt, Gross	12,969,000,000	12,886,000,000	'	'	'	'	3,000,000,000
Debt Instrument, Unamortized Discount	'	'	'	'	$284,000,000	$303,000,000	'

Debt_Senior_Notes_and_Continge

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

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

In Millions, unless otherwise specified

Senior Notes

Senior Notes

Minimum

Minimum

2.5% Contingent Convertible Senior Notes due 2037

2.5% Contingent Convertible Senior Notes due 2037

2.75% Contingent Convertible Senior Notes Due 2035

2.75% Contingent Convertible Senior Notes Due 2035

2.25% Contingent Convertible Senior Notes Due 2038

2.25% Contingent Convertible Senior Notes Due 2038

3.25% Senior Notes due 2016

3.25% Senior Notes due 2016

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

5.375% Senior Notes due 2021

5.375% Senior Notes due 2021

5.75% Senior Notes due 2023

5.75% Senior Notes due 2023

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

Senior Notes

COO Senior Notes [Member]

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

COO Senior Notes [Member]

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investment, Ownership Percentage

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Outstanding Principal Amount

'

'

'

'

$50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

2.50%

'

2.75%

'

2.25%

'

3.25%

'

6.63%

'

'

5.38%

'

5.75%

'

6.63%

6.88%

'

Debt Instrument, Interest Rate, Effective Percentage

'

'

'

'

'

'

8.00%

'

6.86%

'

8.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

12,969

12,886

'

'

'

50

1,168

1,168

396

396

347

347

500

500

650

650

'

700

700

1,100

1,100

'

97

97

Debt Instrument, Unamortized Discount

'

'

$284

$303

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Principal Amount Redeemed Percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

Debt_Bank_Credit_Facilities_Ta

Debt - Bank Credit Facilities Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Line of Credit Facility [Line Items]	'
Number Of Credit Facilities	2
Corporate Revolving Bank Credit Facility	'
Line of Credit Facility [Line Items]	'
Facility structure	'Senior secured revolving
Maturity date	'December 2015
Borrowing capacity	$4,000
Amount outstanding as of March 31, 2014	0
Letters of credit outstanding as of March 31, 2014	23
Oilfield Services Revolving Bank Credit Facility	'
Line of Credit Facility [Line Items]	'
Facility structure	'Senior secured revolving
Maturity date	'November 2016
Borrowing capacity	500
Amount outstanding as of March 31, 2014	464
Letters of credit outstanding as of March 31, 2014	$0

Debt_Bank_Credit_Facilities_Na

Debt - Bank Credit Facilities Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Long-Term Debt Instrument [Line Items]	'	'
Long-term Debt, Gross	$12,969,000,000	$12,886,000,000
Corporate Revolving Bank Credit Facility	'	'
Long-Term Debt Instrument [Line Items]	'	'
Borrowing capacity	4,000,000,000	'
Interest Rate In Addition To Federal Funds Rate	0.50%	'
Line of Credit Facility, Commitment Fee Percentage	0.50%	'
Long-term Debt, Gross	0	0
Line of Credit Facility, Amount Outstanding	0	'
Corporate Revolving Bank Credit Facility | Minimum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimim	1.50%	'
Debt Outstanding Principal Amount	50,000,000	'
Corporate Revolving Bank Credit Facility | Maximum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rage, Effective Percentage Rate Range, Maximum	2.25%	'
Long-term Debt	125,000,000	'
Corporate Revolving Bank Credit Facility | Union Bank N.A. | Minimum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimim	0.50%	'
Corporate Revolving Bank Credit Facility | Union Bank N.A. | Maximum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rage, Effective Percentage Rate Range, Maximum	1.25%	'
Oilfield Services Revolving Bank Credit Facility	'	'
Long-Term Debt Instrument [Line Items]	'	'
Borrowing capacity	500,000,000	'
Interest Rate In Addition To Federal Funds Rate	0.50%	'
Line Of Credit Facility Extended Borrowing Capacity	900,000,000	'
Debt Instrument Interest Rate In Addition To Eurodollar Rate	1.00%	'
Acceleration of Principal Amount Due, Credit Facility	50,000,000	'
Long-term Debt, Gross	464,000,000	405,000,000
Line of Credit Facility, Amount Outstanding	464,000,000	'
Oilfield Services Revolving Bank Credit Facility | In Excess	'	'
Long-Term Debt Instrument [Line Items]	'	'
Line of Credit Facility, Amount Outstanding	$15,000,000	'
Oilfield Services Revolving Bank Credit Facility | Bank Of America N.A.	'	'
Long-Term Debt Instrument [Line Items]	'	'
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimim	1.00%	'
Debt Instrument, Interest Rage, Effective Percentage Rate Range, Maximum	1.75%	'
Oilfield Services Revolving Bank Credit Facility | Bank Of America N.A. | Minimum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Line of Credit Facility, Commitment Fee Percentage	0.38%	'
Percentage above LIBOR rate	2.00%	'
Oilfield Services Revolving Bank Credit Facility | Bank Of America N.A. | Maximum	'	'
Long-Term Debt Instrument [Line Items]	'	'
Line of Credit Facility, Commitment Fee Percentage	0.50%	'
Percentage above LIBOR rate	2.75%	'

Debt_Debt_Fair_Value_of_Other_

Debt Debt - Fair Value of Other Financial Instruments (Table) (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	$11,639	$11,557
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	2,432	2,369
Reported Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	10,522	10,501
Reported Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	$2,434	$2,372

Contingencies_Narrative_Detail

Contingencies - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Commitments and Contingencies Disclosure [Abstract]	'	'
Loss Contingency, Damages Paid, Value	$3,200,000	$600,000
Loss Contingency Term	'10 years	'

Commitments_Undiscounted_Gathe

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) (Gas Gathering and Processing Equipment [Member], USD $)	Mar. 31, 2014
In Millions, unless otherwise specified
Gas Gathering and Processing Equipment [Member]	'
Other Commitments [Line Items]	'
Other Commitment, Due in Next Twelve Months	$1,546
Other Commitment, Due in Second Year	1,830
Other Commitment, Due in Third Year	1,915
Other Commitment, Due in Fourth Year	1,948
Other Commitment, Due in Fifth Year	1,749
Other Commitment, Due after Fifth Year	7,746
Other Commitment	$16,734

Commitments_Narrative_Details

Commitments - Narrative (Details) (USD $)

1 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Apr. 30, 2011

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2011

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Jul. 20, 2011

Jul. 20, 2011

Net Acreage Shortfall [Member]

Net Acreage Maintenance Commitment [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Compressor [Member]

Equipment

Drilling Rigs [Member]

Drilling Rig Leases [Member]

Gas Gathering and Processing Equipment [Member]

Oilfield Services and Other [Member]

Compressor [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Initial Payment [Member]

acre

Rigs

Minimum

Maximum

Compressor

Rigs

Compressor

well

well

Minimum

Maximum

Sundrop Fuels, Inc.

Compressor

Long-term Purchase Commitment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number Of Spud Wells

'

'

'

'

'

'

'

'

'

'

'

'

'

'

488

'

'

'

'

'

'

Equipment, Number of Leased Units

'

'

'

25

'

'

'

'

'

'

'

'

346

'

'

'

'

'

'

'

'

Other Commitment

'

'

'

'

'

'

'

'

'

'

$16,734

$117

'

'

'

'

'

'

'

'

'

Operating Leases, Future Minimum Payments, Due Thereafter

'

'

'

'

'

'

'

'

'

'

'

'

63

'

'

'

'

'

'

'

'

Number Of Drilling Rigs Leased

'

'

'

'

'

'

'

13

'

'

'

'

'

'

'

'

'

'

'

'

'

Lease Term

'

'

'

'

'6 months

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of repurchased equipment

'

'

'

20

'

'

1,435

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Commitment

'

'

'

43

'

'

196

109

'

20

'

'

'

'

'

'

'

'

'

'

'

Payments to Acquire Property, Plant, and Equipment

'

'

'

77

'

'

271

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Contract Termination

'

'

'

8

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

Net Acreage Shortfall

'

14,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Asset Impairment Charges

'

'

28

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Committed Wells Per Year

'

'

'

'

'

'

'

'

'

'

'

'

'

90

'

'

'

'

'

'

'

Drilling Percentage Previous Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

'

'

'

'

Drilling Percentage Current Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.00%

'

'

'

'

'

Guaranteed Gross Profit Margin

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Committed Wells Per Year In Year One

'

'

'

'

'

'

'

'

'

'

'

'

'

270

'

'

'

'

'

'

'

Minimum Committed Wells Per Year In Year Two

'

'

'

'

'

'

'

'

'

'

'

'

'

540

'

'

'

'

'

'

'

Equity Method Investments

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

134

135

155

35

Marketable Securities, Equity Securities

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$25

'

'

'

Other_Liabilities_ShortTerm_Ta

Other Liabilities - Short-Term Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Liabilities Disclosure [Abstract]	'	'
Revenues and royalties due others	$1,499	$1,409
Accrued natural gas, oil and NGL drilling and production costs	285	457
Joint interest prepayments received	530	464
Accrued compensation and benefits	228	320
Other accrued taxes	113	161
Accrued dividends	101	101
Other	538	599
Total other current liabilities	$3,294	$3,511

Other_Liabilities_LongTerm_Tab

Other Liabilities - Long-Term Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Other Long-Term Liabilities [Line Items]	'	'
Financing obligations	$30	$31
Other	433	554
Total other long-term liabilities	851	984
Other liabilities, current	3,294	3,511
Chesapeake Utica L L C [Member]	'	'
Other Long-Term Liabilities [Line Items]	'	'
Conveyance Obligation Noncurrent	242	250
Total other long-term liabilities	257	263
Other liabilities, current	15	13
Chesapeake Cleveland Tonkawa L.L.C	'	'
Other Long-Term Liabilities [Line Items]	'	'
Conveyance Obligation Noncurrent	146	149
Total other long-term liabilities	161	161
Other liabilities, current	$15	$12

Equity_Common_Stock_Table_Deta

Equity - Common Stock Table (Details)	3 Months Ended
	Mar. 30, 2014	Mar. 30, 2013	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'
Common Stock, Shares, Issued Beginning of Period	'	'	665,214,625	666,192,371	669,275,000	666,468,000
Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures	-1,236,000	2,631,000	'	'	'	'
Stock option exercises	259,000	176,000	'	'	'	'
Common Stock, Shares, Issued End of Period	'	'	665,214,625	666,192,371	669,275,000	666,468,000

Equity_Convertible_Preferred_S

Equity - Convertible Preferred Stock Table (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2012

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2012

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock Series A

5.75% Cumulative Convertible Preferred Stock Series A

4.50% Cumulative Convertible Preferred Stock [Member]

4.50% Cumulative Convertible Preferred Stock [Member]

5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]

5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock Series A

5.75% Cumulative Convertible Preferred Stock Series A

5.75% Cumulative Convertible Preferred Stock Series A

4.50% Cumulative Convertible Preferred Stock [Member]

4.50% Cumulative Convertible Preferred Stock [Member]

4.50% Cumulative Convertible Preferred Stock [Member]

5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]

5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]

5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Liquidation Preference Per Share

'

'

'

'

'

'

'

'

'

'

$1,000,000

$1,000,000

'

$1,000,000

$1,000,000

'

$100,000

$100,000

'

$100,000

$100,000

'

Shares outstanding, beginning of period

7,251,515

7,251,515

1,497,000

1,497,000

1,100,000

1,100,000

2,559,000

2,559,000

2,096,000

2,096,000

1,497,000

'

1,497,000

1,100,000

'

1,100,000

2,559,000

'

2,559,000

2,096,000

'

2,096,000

Shares outstanding, end of period

7,251,515

7,251,515

1,497,000

1,497,000

1,100,000

1,100,000

2,559,000

2,559,000

2,096,000

2,096,000

1,497,000

'

1,497,000

1,100,000

'

1,100,000

2,559,000

'

2,559,000

2,096,000

'

2,096,000

Equity_Equity_AOCI_Changes_Net

Equity Equity - AOCI Changes Net of Tax Table (Details) (USD $)

3 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Mar. 30, 2014

Mar. 31, 2014

Mar. 30, 2013

Mar. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

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]

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 Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated Other Comprehensive Income (Loss) Period Start

($162)

'

'

($162)

'

($182)

'

'

($153)

($167)

($178)

($189)

'

'

$0

$5

$8

$7

Other comprehensive income before reclassifications

'

'

3

'

-6

'

3

-1

'

'

'

'

0

-5

'

'

'

'

Amounts reclassified from accumulated other comprehensive income

'

'

6

6

18

18

11

12

'

'

'

'

-5

6

'

'

'

'

Net current period other comprehensive income

9

12

9

'

12

'

14

11

'

'

'

'

-5

1

'

'

'

'

Accumulated Other Comprehensive Income (Loss) Period End

($153)

'

'

($153)

'

($170)

'

'

($153)

($167)

($178)

($189)

'

'

$0

$5

$8

$7

Equity_Equity_AOCI_Reclassific

Equity Equity - AOCI Reclassifications Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 30, 2014	Mar. 31, 2014	Mar. 30, 2013	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$6	$6	$18	$18
Natural Gas, Oil and NGL Revenue [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax	'	11	'	12
Impairment of Investment [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	'	0	'	6
Sale of Investment [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Accumulated Other Comprehensive Income (Loss), Cumulative Changes in Net Gain (Loss) from Cash Flow Hedges, Effect Net of Tax	'	($5)	'	$0

Equity_Narrative_Details

Equity - Narrative (Details)	3 Months Ended
	Mar. 31, 2014
5.75% Cumulative Convertible Preferred Stock	'
Schedule of Capitalization, Equity [Line Items]	'
Preferred Stock, Dividend Rate, Percentage	5.75%
4.50% Cumulative Convertible Preferred Stock [Member]	'
Schedule of Capitalization, Equity [Line Items]	'
Preferred Stock, Dividend Rate, Percentage	4.50%
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%

Equity_Noncontrolling_Interest

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

3 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

1 Months Ended

2 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

3 Months Ended

1 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2012

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2012

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2012

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Nov. 30, 2011

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Nov. 30, 2011

Oct. 31, 2011

Dec. 31, 2011

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Apr. 30, 2014

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Wireless Seismic, Inc. [Member]

Wireless Seismic, Inc. [Member]

Wireless Seismic, Inc. [Member]

Wireless Seismic, Inc. [Member]

Subsequent Event [Member]

acre

well

well

Minimum

Maximum

Preferred Stock

Future [Member]

Future [Member]

Increase

Drilled Wells

well

well

Minimum

Maximum

Maximum

Initial Wells [Member]

Subordinated Units

Common Unit

Common Unit

acre

well

well

well

County

Minimum

Preferred Stock

Preferred Dividend Payments [Member]

Preferred Dividend Payments [Member]

Drilled Wells

Drilled Wells

Non-Controlling Interest

Chesapeake Cleveland Tonkawa L.L.C

acre

well

well

well

well

Minimum

Minimum

acre

well

acre

well

well

well

well

Minimum

well

well

Noncontrolling Interest [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Acres of leasehold land

'

'

'

'

'

'

'

'

'

'

245,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Third-Party investors' contributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,250,000,000

'

'

$1,250,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Dividends, Preferred Stock, Cash

'

'

'

'

'

'

'

'

'

'

1,025,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

950,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of preferred shares exchanged for cash

'

'

'

'

'

'

'

'

'

'

1,250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,250,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Overriding royalty interest, percentage

'

'

'

'

'

'

'

'

'

'

'

3.75%

'

'

3.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Productive Oil Wells, Number of Wells, Net

'

'

'

'

'

'

'

'

'

'

'

3

21

'

'

'

'

'

1,000

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500

1,500

'

1,500

'

1,300

'

'

'

'

'

'

'

'

'

'

Restricted cash and cash equivalents, current

75,000,000

'

75,000,000

'

'

'

'

'

'

'

'

38,000,000

'

38,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

37,000,000

'

'

'

'

'

'

'

Acre Spacing

'

'

'

'

'

'

'

'

'

'

'

160

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Allocated To Overriding Royalty Interest

'

'

'

'

'

'

'

'

'

'

225,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Of Excess Cash Distributed To Third Party Investors Percentage

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of excess cash allocated to preferred shares

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of excess cash allocated to common shares

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of internal rate of return

'

'

'

'

'

'

'

'

'

'

'

9.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Internal return on investment, multiplier

'

'

'

'

'

'

'

'

'

'

'

1.35

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.4

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Redemption price and liquidation preference per preferred share (usd per share)

'

'

'

'

'

'

'

'

'

'

'

$1,230

'

$1,245

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,235

$1,252

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of oil wells committed to drill net, minimum

'

'

'

'

'

'

'

'

'

'

'

25

'

'

'

37.5

'

'

'

'

'

867

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

'

'

12.5

Number Of Net Wells Minimum Cumulative Total

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

'

'

'

'

'

'

'

ORRI Wells Delivered in Period

'

'

'

'

'

'

'

'

'

'

'

3

22

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32

14

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividend Rate, Percentage

'

'

'

'

'

'

'

'

'

'

'

6.00%

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

'

'

'

'

'

'

'

'

'

Preferred Stock, Dividends, Per Share, Cash Paid

'

'

'

'

'

'

'

'

'

'

'

$1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Spacing for Wells Drilled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

150

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of development wells drilled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

89

64

'

'

'

'

'

118

'

'

'

'

'

'

'

'

'

'

'

'

'

22

28

'

'

'

'

'

Number of counties present in the leasehold land (Counties)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13

'

'

'

'

'

'

'

'

'

'

'

'

Amount Payable On Each Short Of Drilling Commitment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

17.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Utica ORRI Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3.00%

3.00%

'

3.00%

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Shares, Issued

665,214,625

669,275,000

666,192,371

666,468,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, par value (usd per share)

$0.01

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of units included in beneficial interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,687,500

12,062,500

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage Of Beneficial Interest Owned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51.00%

'

'

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common shares, outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46,750,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of proceeds from royalty interest conveyed to trust

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

90.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of producing wells

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of gross acres

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45,400

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Acreage Shortfall

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

29,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum amount recoverable by trust under lien

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

263,000,000

'

'

'

'

65,000,000

120,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51.00%

'

Noncontrolling interests

2,136,000,000

'

2,145,000,000

'

'

'

2,136,000,000

2,145,000,000

2,314,000,000

2,327,000,000

'

1,015,000,000

'

1,015,000,000

'

'

'

'

'

'

'

'

306,000,000

'

314,000,000

'

'

'

'

'

'

'

'

'

'

807,000,000

'

'

807,000,000

'

'

'

'

'

'

8,000,000

'

9,000,000

'

'

Net income attributable to noncontrolling interests

$41,000,000

$44,000,000

'

'

$41,000,000

$44,000,000

'

'

'

'

'

$19,000,000

$22,000,000

'

'

'

'

'

'

'

'

'

$5,000,000

$5,000,000

'

'

'

'

'

'

'

'

'

'

'

$19,000,000

$22,000,000

'

'

'

'

'

'

'

'

$1,000,000

$1,000,000

'

'

'

Equity_Noncontrolling_Interest1

Equity - Noncontrolling Interests Distribution Table (Details) (Chesapeake Granite Wash Trust, USD $)	3 Months Ended
	Nov. 30, 2013	Nov. 30, 2012
Noncontrolling Interest [Line Items]	'	'
Distribution Made to Limited Partner, Distribution Date	3-Mar-14	1-Mar-13
Common Unit	'	'
Noncontrolling Interest [Line Items]	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.6624	0.67
Subordinated Units	'	'
Noncontrolling Interest [Line Items]	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0	0.3772

ShareBased_Compensation_ShareB

Share-Based Compensation Share-Based Compensation - Restricted Stock Table (Details) (Restricted stock, USD $)	3 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Mar. 30, 2014	Mar. 31, 2014	Dec. 31, 2013
Restricted stock	'	'	'
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	'	14,355	13,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	3,943	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-2,350	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-638	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	'	14,355	13,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	'	$23.26	$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	$25.13	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$26.41	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$25.69	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	'	$23.26	$23.38

ShareBased_Compensation_ShareB1

Share-Based Compensation Share-Based Compensation - Stock Option Valuation Table (Details)	3 Months Ended
	Mar. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'6 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	48.33%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.97%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.36%

ShareBased_Compensation_ShareB2

Share-Based Compensation Share-Based Compensation - Stock Option Activity Table (Details) (USD $)	0 Months Ended		3 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Mar. 30, 2014	Dec. 30, 2013	Mar. 30, 2014	Mar. 31, 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	'	'	786	'
Share Based Compensation Arrangement By Share Based Payment Award Shares Underlying Options Exercised In Period	'	'	-270	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End	'	'	'	5,784
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Number	'	'	'	1,766
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	'	'	$25.71	'
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	'	'	$18.23	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Expirations in Period	'	'	0	'
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price	'	'	$0	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End	'	'	'	$20.20
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	'	'	'	$18.95
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, Exercisable, Intrinsic Value	'	'	'	12
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	'	'	'	2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End	'	'	'	$31
Weighted Average Contract Life (in years) [Roll Forward]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	'7 years 1 month 24 days	'6 years 7 months 29 days	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'3 years 8 months 21 days	'	'	'

ShareBased_Compensation_ShareB3

Share-Based Compensation Share-Based Compensation - Share-Based Compensation Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Allocated Share-based Compensation Expense	$0	$11
Stock Compensation Plan [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Share Based Compensation General And Administrative Expense	12	20
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	7	21
Share Based Compensation Natural Gas And Oil Production Expenses	4	6
Share Based Compensation Allocated To Marketing Gathering And Compression Expense	2	3
Share Based Compensation Service Operations Expense	2	3
Allocated Share-based Compensation Expense	$27	$53

ShareBased_Compensation_ShareB4

Share-Based Compensation Share-Based Compensation - Performance Shares Table (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Dec. 31, 2012	Mar. 31, 2014	Dec. 31, 2012	Mar. 31, 2014	Dec. 31, 2012
			Year of 2012 [Member]	Year of 2012 [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]
			Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]	Performance Shares [Member]
					Payable 2015 [Member]	Payable 2015 [Member]	Payable 2016 [Member]	Payable 2016 [Member]	Payable 2017 [Member]	Payable 2017 [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	'	'	'	'	834,248	'	1,600,438	'	620,669	'
Fair Value of Share Based Award	'	'	'	'	$21	$23	$52	$35	$16	$17
Share Based Award Liability, Current	'	'	'	'	21	'	45	'	4	'
Allocated Share-based Compensation Expense	$0	$11	$11	$2	'	'	'	'	'	'

ShareBased_Compensation_ShareB5

Share-Based Compensation Share-Based Compensation - Performance Share Unit Breakout (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Allocated Share-based Compensation Expense	$0	$11
Performance Shares [Member]	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'
Employee Service Share-based Compensation, Allocation of Recognized Period Costs, Capitalized Amount	1	4
Share Based Compensation General And Administrative Expense	-1	5
Share Based Compensation Allocated To Marketing Gathering And Compression Expense	$0	$2

ShareBased_Compensation_ShareB6

Share-Based Compensation Share-Based Compensation - Narrative (Details) (USD $)

3 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 30, 2014

Mar. 30, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 30, 2014

Mar. 31, 2013

Restricted stock

Restricted stock

Stock Options

Year of 2012 [Member]

Year of 2012 [Member]

Management [Member]

Management [Member]

Management [Member]

Share-Based Comp Award One Year Anniversary [Member]

Share-Based Comp Award Two Year Anniversary [Member]

Share-Based Comp Award Three Year Anniversary [Member]

Share-Based Comp Award Three Year Anniversary [Member]

Stock Option Award Three Year Anniversary [Member]

Stock Optioin Award Four Year Anniversary [Member]

Stock option Award Five Year Anniversary [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Long-Term Incentive Plan [Member]

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Minimum

Performance Shares [Member]

Performance Shares [Member]

Retention Based Stock Option Award [Member]

Incentive Based Stock Option Award [Member]

Stock Options

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Year of 2014 [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Restricted stock

Restricted stock

Stock Options

Stock Options

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Years of 2013 and 2014 [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Performance Shares [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Year of 2014 [Member]

Year of 2014 [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

TSR is less than zero [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

TSR [Member]

TSR [Member]

Operational Component [Member]

Operational Component [Member]

Performance Shares [Member]

Performance Shares [Member]

Minimum

Maximum

Maximum

Maximum

Minimum

Maximum

Minimum

Maximum

Minimum

Maximum

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

'

'

'

'

'3 years

'

'1 year

'2 years

'3 years

'

'3 years

'4 years

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'first

'second

'third

'third

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Aggregate Intrinsic Value

'

'

$62

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition

'

'

'2 years 6 months

'

'2 years 4 months 26 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax benefit (reduction in tax benefit) from stock-based compensation

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

3

-10

3

10

0

0

Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized

'

'

255

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Stock Options

'

'

'

'

21

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Rights, Percentage

'

'

'

'

'

'

'

33.00%

'

'

'

'

'

'

'

'

'

100.00%

0.00%

125.00%

250.00%

200.00%

0.00%

125.00%

0.00%

62.50%

0.00%

200.00%

'

'

'

'

'

'

Allocated Share-based Compensation Expense

$0

$11

'

'

'

$11

$2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative_and_Hedging_Activit2

Derivative and Hedging Activities - Derivative Instruments Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Fair Value	($726)	($551)
Natural Gas [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	1,125,000,000,000,000	1,009,000,000,000,000
Fair Value	-389	-237
Natural Gas [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	394,000,000,000,000	448,000,000,000,000
Fair Value	-125	-23
Natural Gas [Member] | Three Way Collar [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	387,000,000,000,000	288,000,000,000,000
Fair Value	-48	-7
Natural Gas [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	193,000,000,000,000	193,000,000,000,000
Fair Value	-202	-210
Natural Gas [Member] | Swaptions	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	0	12,000,000,000,000
Fair Value	0	0
Natural Gas [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	151,000,000,000,000	68,000,000,000,000
Fair Value	-14	3
Crude Oil [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	65,000,000	68,200,000
Fair Value	-337	-314
Crude Oil [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	22,800,000	25,300,000
Fair Value	-81	-50
Crude Oil [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	41,900,000	42,500,000
Fair Value	-257	-265
Crude Oil [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	300,000	400,000
Fair Value	$1	$1

Derivative_and_Hedging_Activit3

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]	'	'
Short-term derivative assets	$2	$0
Long-term derivative assets	11	4
Derivative Liability, Current	-417	-208
Long-term derivative liabilities	-395	-445
Derivative Assets (Liabilities), at Fair Value Gross	-799	-649
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-799	-649
Not designated as hedging instruments | Commodity contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	-726	-553
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-726	-553
Not designated as hedging instruments | Interest rate contract	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	-80	-98
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	-80	-98
Designated as Hedging Instrument [Member] | Foreign currency contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value Gross	7	2
Derivative, Gain (Loss) on Derivative, Net	0	0
Derivative Assets (Liabilities), at Fair Value, Net	7	2
Other Current Assets [Member] | Not designated as hedging instruments | Commodity contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	13	29
Derivative, Loss on Derivative	-11	-29
Short-term derivative assets	2	0
Other Noncurrent Assets [Member] | Not designated as hedging instruments | Commodity contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	3	11
Derivative, Loss on Derivative	'	-9
Derivative, Gain on Derivative	1	'
Long-term derivative assets	4	2
Other Current Liabilities [Member] | Not designated as hedging instruments | Commodity contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Gain on Derivative	11	29
Derivative liability, gross liability	-425	-231
Derivative Liability, Current	-414	-202
Other Current Liabilities [Member] | Not designated as hedging instruments | Interest rate contract	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Loss on Derivative	0	0
Derivative liability, gross liability	-3	-6
Derivative Liability, Current	-3	-6
Other Noncurrent Liabilities [Member] | Not designated as hedging instruments | Commodity contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Loss on Derivative	-1	'
Derivative, Gain on Derivative	'	9
Derivative liability, gross liability	-317	-362
Long-term derivative liabilities	-318	-353
Other Noncurrent Liabilities [Member] | Not designated as hedging instruments | Interest rate contract	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative, Loss on Derivative	0	0
Derivative liability, gross liability	-77	-92
Long-term derivative liabilities	-77	-92
Other Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member] | Foreign currency contracts	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	7	2
Derivative, Loss on Derivative	0	0
Long-term derivative assets	$7	$2

Derivative_and_Hedging_Activit4

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Natural gas, oil and NGL Sales	$1,766	$1,453
Natural Gas, Oil and NGL [Member]	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Natural gas, oil and NGL sales	2,148	1,595
Losses on undesignated natural gas, oil and NGL derivatives	-365	-123
Losses on terminated cash flow hedges	-17	-19
Natural gas, oil and NGL Sales	$1,766	$1,453

Derivative_and_Hedging_Activit5

Derivative and Hedging Activities - Interest Income and Interest Expense Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Fair Value, Option, Quantitative Disclosures [Line Items]	'	'
Total interest expense	$39	$21
Interest Expense [Member]	'	'
Fair Value, Option, Quantitative Disclosures [Line Items]	'	'
Interest expense on senior notes	180	186
Interest expense on term loans	29	29
Amortization of loan discount, issuance costs and other	19	19
Interest expense on credit facilities	8	12
Gains on terminated fair value hedges	-1	0
(Gains) losses on undesignated interest rate derivatives	-18	4
Capitalized interest	-178	-229
Total interest expense	$39	$21

Derivative_and_Hedging_Activit6

Derivative and Hedging Activities - Cash Flow Hedges Components of AOCI Table (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Mar. 30, 2014

Mar. 31, 2014

Mar. 30, 2013

Mar. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

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]

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]

Balance Before Tax

Balance Before Tax

Balance Before Tax

Balance Before Tax

Balance Before Tax

Balance Before Tax

Balance After Tax

Balance After Tax

Balance After Tax

Balance After Tax

Balance After Tax

Balance After Tax

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated Other Comprehensive Income (Loss) Period Start

($153)

($162)

'

($162)

'

($182)

'

'

($247)

($269)

($287)

($304)

'

'

($153)

($167)

($178)

($189)

Other Comprehensive Income Before Reclassifications, Net of Tax

'

'

'

'

'

'

4

-2

'

'

'

'

3

-1

'

'

'

'

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

'

'

6

6

18

18

18

19

'

'

'

'

11

12

'

'

'

'

Accumulated Other Comprehensive Income (Loss) Period End

($153)

($162)

'

($153)

'

($170)

'

'

($247)

($269)

($287)

($304)

'

'

($153)

($167)

($178)

($189)

Derivative_and_Hedging_Activit7

Derivative and Hedging Activities Derivative and Hedging Activities - Fair Value of Recurring Assets and Liabilities Table (Details) (USD $)	Mar. 31, 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	($799)	($649)
Commodity contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Asset	16	40
Derivative Liability	-742	-593
Interest rate contract	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Interest Rate Derivative Liabilities, at Fair Value	-80	-98
Foreign currency contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	7	2
Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value, Net	0	0
Fair Value, Inputs, Level 1 [Member] | Commodity contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Asset	0	0
Derivative Liability	0	0
Fair Value, Inputs, Level 1 [Member] | Interest rate contract	'	'
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, Inputs, Level 1 [Member] | Foreign currency contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Assets (Liabilities), at Fair Value, Net	-292	-171
Fair Value, Inputs, Level 2 [Member] | Commodity contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Asset	10	25
Derivative Liability	-229	-100
Fair Value, Inputs, Level 2 [Member] | Interest rate contract	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Interest Rate Derivative Liabilities, at Fair Value	-80	-98
Fair Value, Inputs, Level 2 [Member] | Foreign currency contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	7	2
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	-507	-478
Fair Value, Inputs, Level 3 [Member] | Commodity contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Derivative Asset	6	15
Derivative Liability	-513	-493
Fair Value, Inputs, Level 3 [Member] | Interest rate contract	'	'
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, Inputs, Level 3 [Member] | Foreign currency contracts	'	'
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]	'	'
Foreign Currency Contracts, Asset, Fair Value Disclosure	$0	$0

Derivative_and_Hedging_Activit8

Derivative and Hedging Activities Derivative and Hedging Activities - Fair Value Level 3 Measurements Table (Details) (USD $)

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 30, 2014

Mar. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2012

In Millions, unless otherwise specified

Interest rate contract

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Fair Value, Inputs, Level 3 [Member]

Natural Gas And Oil Sales [Member]

Natural Gas And Oil Sales [Member]

Interest Expense [Member]

Interest Expense [Member]

Interest rate contract

Interest rate contract

Interest rate contract

Interest rate contract

Commodity contracts

Commodity contracts

Commodity contracts

Commodity contracts

Commodity contracts

Commodity contracts

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

($2)

'

'

'

'

'

'

$0

$0

'

'

($507)

($478)

($785)

($1,016)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Gain Loss Included In Earnings Or Change In Net Assets Unrealized

'

-80

194

0

-1

0

-1

'

'

-80

194

'

'

'

'

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

'

'

'

'

'

0

0

'

'

55

37

'

'

'

'

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

'

'

'

'

'

'

-1

'

'

'

0

'

'

'

'

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

'

'

'

'

'

0

'

'

'

-4

'

'

'

'

'

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

'

($57)

$191

$0

($2)

'

'

'

'

'

'

'

'

'

'

Derivative_and_Hedging_Activit9

Derivative and Hedging Activities Derivative and Hedging Activities - Quantitative Disclosures Level 3 Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Natural Gas [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Fair Value Assets Unobservable Input Description	'Natural gas price volatility curves
Weighted Average Of Price Volatility Curve Percentage	24.32%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	($251)
Natural Gas [Member] | Minimum	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Price Volatility Curve	18.03%
Natural Gas [Member] | Maximum	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Price Volatility Curve	38.37%
Crude Oil [Member]	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Fair Value Assets Unobservable Input Description	'Oil price volatility curves
Weighted Average Of Price Volatility Curve Percentage	15.43%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	($256)
Crude Oil [Member] | Minimum	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Price Volatility Curve	10.56%
Crude Oil [Member] | Maximum	'
Fair Value Inputs, Assets, Quantitative Information [Line Items]	'
Price Volatility Curve	21.78%

Recovered_Sheet2

Derivative and Hedging Activities - Narrative (Details)

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2006

USD ($)

USD ($)

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Swap

Swap

Basis Derivative [Member]

Price Risk Derivative [Member]

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

USD ($)

Credit Risk

Energy Related Derivative [Member]

Semi-Annual Collateral Dates

Between Semi-Annual Collateral Dates

USD ($)

USD ($)

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Maturity Payment [Member]

Maturity Payment [Member]

Senior Notes

counterparty

counterparty

MMBoe

MMBoe

MMBoe

USD ($)

USD ($)

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Senior Notes

Senior Notes

Cross Currency Interest Rate Contract [Member]

USD ($)

EUR (€)

USD ($)

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

USD ($)

USD ($)

EUR (€)

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Rate Derivatives, at Fair Value, Net

'

'

'

'

'

'

'

$80,000,000

$98,000,000

'

'

'

'

'

'

'

'

'

'

Derivative, Amount of Hedged Item

'

'

'

'

'

'

'

2,250,000,000

2,250,000,000

'

'

'

'

'

'

'

'

'

'

Number of counterparties in hedge facility

'

'

17

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

1,063,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

17,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

26,000,000

224,000,000

'

'

'

'

'

'

'

'

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

'

'

'

'

'

1.65

1.3

'

'

'

'

'

'

'

'

'

'

'

'

Duration gains will be recognized on terminated qualifying interest rate derivative transactions, years

'7 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Deferred (Gain) Loss on Discontinuation of Fair Value Hedge

13,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Semi Annual Interest Rate Swap Payments By Counterparty

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,000,000

'

'

344,000,000

'

Semi Annual Interest Rate Swap Payments By Chesapeake

'

'

'

'

'

'

'

'

'

'

'

'

'

17,000,000

'

'

459,000,000

'

'

Dollar Equivalent Interest Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

7.49%

7.49%

'

'

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3769

'

1.3743

'

'

1.3325

Derivative liability, gross liability

'

'

'

'

'

'

'

'

'

'

'

'

'

7,000,000

'

'

'

'

'

Euro-denominated debt in notes payable, adjusted value

12,969,000,000

12,886,000,000

'

'

'

'

'

'

'

'

'

473,000,000

473,000,000

473,000,000

'

'

'

'

'

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

148,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Flow Hedges, Accumulated OCI Balance

153,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected amount to be transferred of during the next 12 months

$23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_D2

Natural Gas and Oil Property Divestitures - Joint Ventures Table (Details) (USD $)

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2014

Jun. 30, 2013

Dec. 31, 2011

Mar. 31, 2014

Feb. 28, 2011

Mar. 31, 2014

Nov. 30, 2010

Mar. 31, 2014

Jan. 31, 2010

Mar. 31, 2014

Nov. 30, 2008

Mar. 31, 2014

Sep. 30, 2008

Mar. 31, 2014

Jul. 31, 2008

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

JV Mississippi Lime

JV Mississippi Lime

JV Utica

JV Utica

JV Niobrara

JV Niobrara

JV Eagle Ford

JV Eagle Ford

JV Barnett Shale

JV Barnett Shale

JVMarcellus

JVMarcellus

JV Fayetteville

JV Fayetteville

JV Haynesville And Bossier

JV Haynesville And Bossier

Payment Remaining [Member]

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

JV Mississippi Lime

JV Mississippi Lime

Joint Ventures [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Joint Venture Partner

'

'

'Sinopec

'TOT

'

'CNOOC

'

'CNOOC

'

'TOT

'

'STO

'

'BP

'

'FCX

'

'

'

Joint Venture Date

'

'

'June 2013

'December 2011

'

'February 2011

'

'November 2010

'

'January 2010

'

'November 2008

'

'September 2008

'

'July 2008

'

'

'

Interest Sold

'

'

50.00%

25.00%

'

33.30%

'

33.30%

'

25.00%

'

32.50%

'

25.00%

'

20.00%

'

'

'

Proceeds from Divestiture of Interest in Joint Venture

$8,049

'

$949

$610

'

$570

'

$1,120

'

$800

'

$1,250

'

$1,100

'

$1,650

'

$71

$90

Total Drilling Carries

9,035

'

0

1,422

'

697

'

1,080

'

1,403

'

2,125

'

800

'

1,508

'

'

'

Total Cash And Drilling Carry Proceeds

17,084

'

949

2,032

'

1,267

'

2,200

'

2,203

'

3,375

'

1,900

'

3,158

'

'

'

Drilling Carries Remaining

$542

$0

'

'

$478

'

$64

'

$0

'

$0

'

$0

'

$0

'

$0

'

'

Percentage of Total Payment by Joint Venture Partner

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

'

Percentage Reimbursed

'

'

'

'

60.00%

'

67.00%

'

'

'

'

'

'

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_D3

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

3 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

3 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 30, 2013

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

Sep. 30, 2009

Aug. 31, 2009

Aug. 31, 2009

Aug. 31, 2009

Aug. 31, 2009

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 Reserves

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 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 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [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 Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcf

MBbls

MBbls

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)

$6,031

'

'

'

$744

'

'

'

'

$853

'

'

'

'

$1,150

'

'

'

$180

'

'

'

'

$370

'

'

'

'

$412

'

'

'

$600

'

'

'

'

$622

'

'

'

'

$1,100

'

'

'

Proved Developed Reserves (Volume)

'

1,216,000,000,000

5,700,000

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

'

'

67,000,000,000

200,000

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)

1,334,000,000,000

'

'

'

'

160,000,000,000

'

'

'

'

177,000,000,000

'

'

'

390,000,000,000

'

'

'

'

46,000,000,000

'

'

'

'

68,000,000,000

'

'

'

98,000,000,000

'

'

'

'

93,000,000,000

'

'

'

'

94,000,000,000

'

'

'

208,000,000,000

'

'

'

Natural_Gas_and_Oil_Property_D4

Natural Gas and Oil Property Divestitures - VPP Volumes Produced During Period Table (Details)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
	Mcfe	Mcfe
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	39,400,000,000	44,900,000,000
Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	35,500,000,000	40,500,000,000
Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	182,700	236,400
NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	451,700	526,500
VPP 10 Anadarko Basin Granite Wash [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	5,500,000,000	6,900,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,800,000,000	3,700,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	109,000	154,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	345,200	407,700
VPP 9 Mid-Continent [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	4,900,000,000	5,500,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	4,000,000,000	4,400,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	49,000	56,200
VPP 9 Mid-Continent [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	106,500	118,800
VPP 8 Barnett Shale [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	15,700,000,000	18,000,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	15,700,000,000	18,000,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 8 Barnett Shale [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 6 East Texas and Texas Gulf Coast [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	1,200,000,000	1,200,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,100,000,000	1,200,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	6,000	6,000
VPP 6 East Texas and Texas Gulf Coast [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 5 South Texas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	1,800,000,000	2,000,000,000
VPP 5 South Texas [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,700,000,000	2,000,000,000
VPP 5 South Texas [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	6,300	6,000
VPP 5 South Texas [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 4 Anadarko and Arkoma Basins [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	2,400,000,000	2,700,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,300,000,000	2,600,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	12,400	14,200
VPP 4 Anadarko and Arkoma Basins [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 3 Anadarko Basin [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	1,900,000,000	2,100,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,900,000,000	2,100,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 3 Anadarko Basin [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	2,400,000,000	2,700,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,400,000,000	2,700,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 2 Texas, Oklahoma and Kansas [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 1 Kentucky and West Virginia [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Reserves (Energy) (Duration)	3,600,000,000	3,800,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	3,600,000,000	3,800,000,000
VPP 1 Kentucky and West Virginia [Member] | Oil [Member]	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0
VPP 1 Kentucky and West Virginia [Member] | NGL Reserves	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0

Natural_Gas_and_Oil_Property_D5

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

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

Mar. 31, 2014

31-May-11

Mar. 31, 2014

31-May-11

Mar. 31, 2014

31-May-11

Mar. 31, 2014

31-May-11

Mar. 31, 2014

Sep. 30, 2010

Mar. 31, 2014

Sep. 30, 2010

Mar. 31, 2014

Sep. 30, 2010

Mar. 31, 2014

Sep. 30, 2010

Mar. 31, 2014

Feb. 28, 2010

Mar. 31, 2014

Feb. 28, 2010

Mar. 31, 2014

Feb. 28, 2010

Mar. 31, 2014

Feb. 28, 2010

Mar. 31, 2014

Aug. 31, 2009

Mar. 31, 2014

Aug. 31, 2009

Mar. 31, 2014

Aug. 31, 2009

Mar. 31, 2014

Aug. 31, 2009

Mar. 31, 2014

Dec. 31, 2008

Mar. 31, 2014

Dec. 31, 2008

Mar. 31, 2014

Dec. 31, 2008

Mar. 31, 2014

Dec. 31, 2008

Mar. 31, 2014

Aug. 31, 2008

Mar. 31, 2014

Aug. 31, 2008

Mar. 31, 2014

Aug. 31, 2008

Mar. 31, 2014

Aug. 31, 2008

Mar. 31, 2014

31-May-08

Mar. 31, 2014

31-May-08

Mar. 31, 2014

31-May-08

Mar. 31, 2014

31-May-08

Mar. 31, 2014

Dec. 31, 2007

Mar. 31, 2014

Dec. 31, 2007

Mar. 31, 2014

Dec. 31, 2007

Mar. 31, 2014

Dec. 31, 2007

Mar. 31, 2014

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

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 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [Member]

VPP 5 South Texas [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

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Reserve Volume Remaining

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcf

MBbls

MBbls

Mcfe

Reserve Volume Remaining

Reserve Volume Remaining

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcfe

Mcf

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

MBbls

Reserve Volume Remaining

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Mcf

MBbls

MBbls

Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contract Term

'

'

'

'

'

'

'

'

'95 months

'

'

'

'

'83 months

'

'

'

'

'

'

'

'17 months

'

'

'

'

'

'

'

'70 months

'

'

'

'

'

'

'

'34 months

'

'

'

'

'

'

'

'33 months

'

'

'

'

'

'

'

'64 months

'

'

'

'

'

'

'

'61 months

'

'

'

'

'

'

'

'105 months

'

'

'

'

'

'

Proved Developed Reserves (Volume)

'

'

1,216,000,000,000

417,500,000,000

5,700,000

2,900,000

14,000,000

7,800,000

'

45,800,000,000

1,600,000

5,600,000

'

'

138,000,000,000

84,700,000,000

1,700,000

1,000,000

4,800,000

2,200,000

'

'

390,000,000,000

80,900,000,000

0

0

0

0

'

'

44,000,000,000

20,300,000,000

300,000

100,000

0

0

'

'

67,000,000,000

15,200,000,000

200,000

100,000

0

0

'

'

95,000,000,000

22,000,000,000

500,000

100,000

0

0

'

'

93,000,000,000

29,200,000,000

0

0

0

0

'

'

94,000,000,000

17,600,000,000

0

0

0

0

'

'

208,000,000,000

101,800,000,000

0

0

0

0

Proved Developed Reserves (Energy)

1,334,000,000,000

482,000,000,000

'

'

'

'

'

'

89,200,000,000

'

'

'

177,000,000,000

104,000,000,000

'

'

'

'

'

'

390,000,000,000

80,900,000,000

'

'

'

'

'

'

46,000,000,000

21,100,000,000

'

'

'

'

'

'

68,000,000,000

15,500,000,000

'

'

'

'

'

'

98,000,000,000

22,700,000,000

'

'

'

'

'

'

93,000,000,000

29,200,000,000

'

'

'

'

'

'

94,000,000,000

17,600,000,000

'

'

'

'

'

'

208,000,000,000

101,800,000,000

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_D6

Natural Gas and Oil Property Divestitures - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014	Jun. 30, 2013
			Corporate Joint Venture [Member]	Corporate Joint Venture [Member]	JV Marcellus, Barnett and Utica [Member]	JV Marcellus, Barnett and Utica [Member]	Corporate VPP [Member]	JV Mississippi Lime
Business Acquisition [Line Items]	'	'	'	'	'	'	'	'
Proceeds from divestitures of proved and unproved properties	$49,000,000	$190,000,000	$41,000,000	$165,000,000	'	'	'	'
Number of Joint Ventures	'	'	8	'	'	'	'	'
Number of Resource Plays	'	'	8	'	'	'	'	'
Proceeds from Divestiture of Interest in Joint Venture	8,049,000,000	'	8,000,000,000	'	8,000,000	25,000,000	'	949,000,000
Total Drilling Carries	9,035,000,000	'	'	'	'	'	'	0
Oil And Gas Benefit From Drilling Carries	'	'	188,000,000	180,000,000	'	'	'	'
Gain (Loss) on Sale of Other Assets	'	'	'	'	'	'	$0	'

Investments_Schedule_of_Invest

Investments - Schedule of Investments Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Jul. 20, 2011
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]	'	'	'
Investments	$288	$477	'
FTS International, Inc.	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Ownership Percentage	30.00%	30.00%	'
Equity Method Investments	129	138	'
Chaparral Energy, Inc.	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Ownership Percentage	0.00%	20.00%	'
Equity Method Investments	0	143	'
Sundrop Fuels, Inc.	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Ownership Percentage	56.00%	56.00%	'
Equity Method Investments	134	135	155
Other Investment Companies [Member]	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Ownership Percentage	0.00%	0.00%	'
Cost Method Investments	$25	$61	'

Investments_Narrative_Details

Investments - Narrative (Details) (USD $)

3 Months Ended

3 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Mar. 31, 2014

Mar. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Sep. 30, 2013

Dec. 31, 2013

Jul. 20, 2011

Mar. 31, 2014

Jul. 20, 2011

FTS International, Inc.

FTS International, Inc.

Chaparral Energy, Inc.

Chaparral Energy, Inc.

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Other Investment Companies [Member]

Initial Payment [Member]

Sundrop Fuels, Inc.

Schedule of Equity Method Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investments

'

'

$129

$138

$0

$143

$134

'

$135

$155

'

$35

Marketable Securities, Equity Securities

'

'

'

'

'

'

25

'

'

'

'

'

Positive equity method adjustments

'

'

15

'

'

'

'

3

'

'

'

'

Interest Costs Capitalized

'

'

'

'

'

'

2

'

'

'

'

'

Equity method accretion adjustments

'

'

6

'

'

'

'

65

'

'

'

'

Excess carrying value of investment over underlying equity in net assets

'

'

48

'

'

'

'

'

'

'

'

'

Equity Method Investment, Difference Between Carrying Amount and Underlying Equity Attributable to Goodwill

'

'

14

'

'

'

'

'

'

'

'

'

Proceeds from sales of investments

239

0

'

'

209

'

'

'

'

'

30

'

Gain on Sale of Investments

'

'

'

'

73

'

'

'

'

'

'

'

Loss on Sale of Investments

'

'

'

'

'

'

'

'

'

'

$6

'

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014
Chesapeake Granite Wash Trust | Consolidated Entities	'
Variable Interest Entity [Line Items]	'
VIE's cash and cash equivalents	1
Consolidation Net Oil and Gas Property Assets	298
VIE's, short-term derivative liabilities	6
VIE's, other current liabilities	19
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of acquisition	10.00%
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. | Minimum | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of royalty minimum	7.00%
Corporate Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. | Maximum | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Other Commitment	25
Percentage of royalty maximum	22.50%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of acquisition	90.00%
Partner Ownership Requirement [Member] | Mineral Acquisition Company I, L.P. | Maximum | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Other Commitment	225

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
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	($23)	($49)
Natural Gas Compressors [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	-26	0
Gas Gathering and Processing Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	3	-69
Exploration and Production Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	2	1
Land and Building [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	0	22
Other Assets	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	($2)	($3)

Other_Property_and_Equipment_O1

Other Property and Equipment Other Property and Equipment - Assets Held For Sale Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	$627	$730
Compressor [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	322	285
Natural Gas Processing Plant [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	10	11
Exploration and Production Equipment [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	58	29
Property, Plant and Equipment, Other Types	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	$237	$405

Other_Property_and_Equipment_N1

Other Property and Equipment - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Property, Plant and Equipment [Line Items]	'	'
Reclassification from held for sale to held for use	'	$116
Net gains on sales of fixed assets	-23	-49
Compressor [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Equipment, Number of Units	102	'
Compressor [Member] | Access Midstream Partners, L.P. [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	24	'
Proceeds from Sale of Property, Plant, and Equipment	159	'
Gas Gathering and Processing Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	3	-69
Gas Gathering and Processing Equipment [Member] | Sale to Western Gas Partners, LP [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	55	'
Proceeds from Sale of Property, Plant, and Equipment	134	'
Land and Building [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Net gains on sales of fixed assets	$0	$22

Impairments_of_Fixed_Assets_an2

Impairments of Fixed Assets and Other - Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Impaired Long-Lived Assets Held and Used [Line Items]	'	'
Impairments of fixed assets and other	$20	$27
Exploration and Production Equipment [Member]	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'
Impairments of fixed assets and other	20	0
Land and Building [Member]	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'
Impairments of fixed assets and other	$0	$27

Impairments_of_Fixed_Assets_an3

Impairments of Fixed Assets and Other - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Significant Acquisitions and Disposals [Line Items]	'	'
Impairments of fixed assets and other	$20	$27
Drilling Rigs [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Gain (Loss) on Contract Termination	8	'
Exploration and Production Equipment [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Impairment of Long-Lived Assets to be Disposed of	12	'
Impairments of fixed assets and other	20	0
Land and Building [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Impairments of fixed assets and other	0	27
Drilling Rigs [Member]	'	'
Significant Acquisitions and Disposals [Line Items]	'	'
Number of repurchased equipment	20	'
Payments to Acquire Property, Plant, and Equipment	77	'
Gain (Loss) on Contract Termination	$8	'

Restructuring_and_Other_Termin1

Restructuring and Other Termination Benefits - Table (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	($3)	$13	'
Restructuring and other termination costs	-7	133	'
Ceo Aubrey K Mcclendon [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	-4	64	'
Ceo Aubrey K Mcclendon [Member] | Cash Salary and Bonus Costs [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	0	11	'
Ceo Aubrey K Mcclendon [Member] | Claw-Back Bonus [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	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	22	'
Ceo Aubrey K Mcclendon [Member] | Acceleration of Performance Shares [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	-4	13	'
Ceo Aubrey K Mcclendon [Member] | Other Costs Associated with Retirement [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	0	7	'
VSP Program	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	0	56	56
VSP Program | Cash Salary and Bonus Costs [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	0	30	'
VSP Program | Acceleration of Restricted Stock Awards [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	0	24	'
VSP Program | Other Costs Associated with Retirement [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	$0	$2	'

Restructuring_and_Other_Termin2

Restructuring and Other Termination Benefits - Narrative (Details) (USD $)	3 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Feb. 07, 2013	Dec. 31, 2012
				Employee	Employee
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'	'
Severance Costs	($3)	$13	'	'	'
Ceo Aubrey K Mcclendon [Member]	'	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'	'
Severance Costs	-4	64	'	'	'
VSP Program	'	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'	'
Severance Costs	$0	$56	$56	'	'
Number of Employees Selected for Voluntary Program	'	'	'	'	275
Number of Employees That Accepted Voluntary Program	'	'	'	211	'

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Assets/Liabilities Table (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair Value, Net Asset (Liability)	($2)	($2)
Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Assets, Fair Value Disclosure	78	80
Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Liabilities, Fair Value Disclosure	-80	-82
Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair Value, Net Asset (Liability)	-2	-2
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Assets, Fair Value Disclosure	78	80
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Liabilities, Fair Value Disclosure	-80	-82
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member] | Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Fair Value, Net Asset (Liability)	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Assets, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 3 [Member] | Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other Liabilities, Fair Value Disclosure	$0	$0

Segment_Reporting_Table_Detail

Segment Reporting - Table (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Segment Reporting Information [Line Items]	'	'	'
Revenues	$5,046	$3,424	'
Income (Loss) Before Income Taxes	746	165	'
Total Assets	42,605	'	41,782
Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	1,766	1,453	'
Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	3,015	1,781	'
Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	239	186	'
Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	26	4	'
Reportable Subsegments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	5,046	3,424	'
Income (Loss) Before Income Taxes	746	165	'
Total Assets	42,605	'	41,782
Intersubsegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	'
Operating Segments [Member] | Reportable Subsegments [Member] | Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	1,766	1,453	'
Income (Loss) Before Income Taxes	687	170	'
Total Assets	36,102	'	35,341
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	5,423	3,529	'
Income (Loss) Before Income Taxes	105	129	'
Total Assets	2,950	'	2,430
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	510	538	'
Income (Loss) Before Income Taxes	-42	22	'
Total Assets	2,058	'	2,018
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	26	10	'
Income (Loss) Before Income Taxes	60	-58	'
Total Assets	5,516	'	5,750
Intersegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	'
Intersegment Eliminations [Member] | Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	'
Intersegment Eliminations [Member] | Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-2,408	-1,748	'
Intersegment Eliminations [Member] | Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-271	-352	'
Intersegment Eliminations [Member] | Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	-6	'
Intersegment Eliminations [Member] | Reportable Subsegments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-2,679	-2,106	'
Income (Loss) Before Income Taxes	-64	-98	'
Total Assets	-4,021	'	-3,757
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	$2,679	$2,106	'

Segment_Information_Narrative_

Segment Information - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
	Segment
Segment Reporting Information [Line Items]	'	'
Number of reportable segments	3	'
Revenues	$5,046	$3,424
Intersegment Eliminations [Member]	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	0	0
Marketing, Gathering And Compression	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	3,015	1,781
Marketing, Gathering And Compression | Intersegment Eliminations [Member]	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	-2,408	-1,748
Oilfield Services	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	239	186
Oilfield Services | Intersegment Eliminations [Member]	'	'
Segment Reporting Information [Line Items]	'	'
Revenues	($271)	($352)

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheet (Details) (USD $)	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$1,004	$837	$33	$287
Restricted cash	75	75	'	'
Other	3,196	2,744	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	4,275	3,656	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	32,872	32,593	'	'
Other property and equipment, net	4,023	3,811	'	'
Property and equipment held for sale, net	627	730	'	'
Total Property and Equipment, Net	37,522	37,134	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	808	992	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	42,605	41,782	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,958	5,515	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	5,958	5,515	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	12,653	12,886	'	'
Deferred income tax liabilities	3,828	3,407	'	'
Other long-term liabilities	1,689	1,834	'	'
Total Long-Term Liabilities	18,170	18,127	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,341	15,995	'	'
Noncontrolling interests	2,136	2,145	'	'
Total Equity	18,477	18,140	18,014	'
TOTAL LIABILITIES AND EQUITY	42,605	41,782	'	'
Parent	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	974	799	0	228
Restricted cash	0	0	'	'
Other	88	103	'	'
Intercompany receivable, net	25,431	25,369	'	'
Total Current Assets	26,493	26,271	'	'
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 assets	109	111	'	'
Investments in subsidiaries and intercompany advances	2,387	2,349	'	'
TOTAL ASSETS	28,989	28,731	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	550	300	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	550	300	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	11,539	11,831	'	'
Deferred income tax liabilities	293	209	'	'
Other long-term liabilities	266	396	'	'
Total Long-Term Liabilities	12,098	12,436	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,341	15,995	'	'
Noncontrolling interests	0	0	'	'
Total Equity	16,341	15,995	'	'
TOTAL LIABILITIES AND EQUITY	28,989	28,731	'	'
Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0	'	'
Other	2,862	2,392	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	2,862	2,392	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	29,891	29,295	'	'
Other property and equipment, net	2,523	2,315	'	'
Property and equipment held for sale, net	569	701	'	'
Total Property and Equipment, Net	32,983	32,311	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	962	1,146	'	'
Investments in subsidiaries and intercompany advances	-201	-251	'	'
TOTAL ASSETS	36,606	35,598	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,445	5,211	'	'
Intercompany payable, net	24,922	24,752	'	'
Total Current Liabilities	30,367	29,963	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	2,834	2,264	'	'
Other long-term liabilities	1,018	1,022	'	'
Total Long-Term Liabilities	3,852	3,286	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	2,387	2,349	'	'
Noncontrolling interests	0	0	'	'
Total Equity	2,387	2,349	'	'
TOTAL LIABILITIES AND EQUITY	36,606	35,598	'	'
Non-Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	75	39	33	59
Restricted cash	82	82	'	'
Other	623	616	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	780	737	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	3,075	3,113	'	'
Other property and equipment, net	1,501	1,497	'	'
Property and equipment held for sale, net	58	29	'	'
Total Property and Equipment, Net	4,634	4,639	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	109	111	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	5,523	5,487	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	392	379	'	'
Intercompany payable, net	257	593	'	'
Total Current Liabilities	649	972	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	1,114	1,055	'	'
Deferred income tax liabilities	1,117	847	'	'
Other long-term liabilities	777	788	'	'
Total Long-Term Liabilities	3,008	2,690	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	1,866	1,825	'	'
Noncontrolling interests	0	0	'	'
Total Equity	1,866	1,825	'	'
TOTAL LIABILITIES AND EQUITY	5,523	5,487	'	'
Eliminations	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	-45	-1	0	0
Restricted cash	-7	-7	'	'
Other	-377	-367	'	'
Intercompany receivable, net	-25,431	-25,369	'	'
Total Current Assets	-25,860	-25,744	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	-94	185	'	'
Other property and equipment, net	-1	-1	'	'
Property and equipment held for sale, net	0	0	'	'
Total Property and Equipment, Net	-95	184	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	-372	-376	'	'
Investments in subsidiaries and intercompany advances	-2,186	-2,098	'	'
TOTAL ASSETS	-28,513	-28,034	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	-429	-375	'	'
Intercompany payable, net	-25,179	-25,345	'	'
Total Current Liabilities	-25,608	-25,720	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	-416	87	'	'
Other long-term liabilities	-372	-372	'	'
Total Long-Term Liabilities	-788	-285	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	-4,253	-4,174	'	'
Noncontrolling interests	2,136	2,145	'	'
Total Equity	-2,117	-2,029	'	'
TOTAL LIABILITIES AND EQUITY	($28,513)	($28,034)	'	'

Condensed_Consolidating_Statem

Condensed Consolidating Statement Of Operations (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
REVENUES	'	'
Natural gas, oil and NGL	$1,766	$1,453
Marketing, gathering and compression	3,015	1,781
Oilfield services	265	190
Total Revenues	5,046	3,424
OPERATING EXPENSES	'	'
Natural gas, oil and NGL production	288	307
Production taxes	50	53
Marketing, gathering and compression	2,980	1,745
Oilfield services	220	155
General and administrative	79	110
Restructuring and other termination costs	-7	133
Natural gas, oil and NGL depreciation, depletion and amortization	628	648
Depreciation and amortization of other assets	78	78
Impairment of natural gas and oil properties	0	0
Impairments of fixed assets and other	20	27
Net gains on sales of fixed assets	-23	-49
Total Operating Expenses	4,313	3,207
INCOME (LOSS) FROM OPERATIONS	733	217
OTHER INCOME (EXPENSE):	'	'
Interest expense	-39	-21
Losses on investments	-21	-37
Net gain on sales of investments	67	0
Other income	6	6
Equity in net earnings of subsidiary	0	0
Total Other Income (Expense)	13	-52
INCOME (LOSS) BEFORE INCOME TAXES	746	165
INCOME TAX EXPENSE	280	63
NET INCOME	466	102
Net income attributable to noncontrolling interests	-41	-44
Net income attributable to Chesapeake	425	58
Other Comprehensive Income (Loss), Net of Tax	9	12
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	434	70
Parent	'	'
REVENUES	'	'
Natural gas, oil and NGL	0	0
Marketing, gathering and compression	0	0
Oilfield services	0	0
Total Revenues	0	0
OPERATING EXPENSES	'	'
Natural gas, oil and NGL production	0	0
Production taxes	0	0
Marketing, gathering and compression	0	0
Oilfield services	0	0
General and administrative	0	0
Restructuring and other termination costs	0	0
Natural gas, oil and NGL depreciation, depletion and amortization	0	0
Depreciation and amortization of other assets	0	0
Impairment of natural gas and oil properties	0	0
Impairments of fixed assets and other	0	0
Net gains on sales of fixed assets	0	0
Total Operating Expenses	0	0
INCOME (LOSS) FROM OPERATIONS	0	0
OTHER INCOME (EXPENSE):	'	'
Interest expense	-192	-219
Losses on investments	0	0
Net gain on sales of investments	0	'
Other income	344	216
Equity in net earnings of subsidiary	330	60
Total Other Income (Expense)	482	57
INCOME (LOSS) BEFORE INCOME TAXES	482	57
INCOME TAX EXPENSE	57	-1
NET INCOME	425	58
Net income attributable to noncontrolling interests	0	0
Net income attributable to Chesapeake	425	58
Other Comprehensive Income (Loss), Net of Tax	2	-2
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	427	56
Guarantor Subsidiaries	'	'
REVENUES	'	'
Natural gas, oil and NGL	1,545	1,322
Marketing, gathering and compression	3,014	1,778
Oilfield services	0	0
Total Revenues	4,559	3,100
OPERATING EXPENSES	'	'
Natural gas, oil and NGL production	269	296
Production taxes	49	51
Marketing, gathering and compression	2,979	1,742
Oilfield services	17	23
General and administrative	53	87
Restructuring and other termination costs	-7	131
Natural gas, oil and NGL depreciation, depletion and amortization	568	591
Depreciation and amortization of other assets	39	48
Impairment of natural gas and oil properties	0	0
Impairments of fixed assets and other	0	27
Net gains on sales of fixed assets	-24	-49
Total Operating Expenses	3,943	2,947
INCOME (LOSS) FROM OPERATIONS	616	153
OTHER INCOME (EXPENSE):	'	'
Interest expense	0	-8
Losses on investments	-15	-37
Net gain on sales of investments	67	'
Other income	-141	42
Equity in net earnings of subsidiary	-17	-87
Total Other Income (Expense)	-106	-90
INCOME (LOSS) BEFORE INCOME TAXES	510	63
INCOME TAX EXPENSE	198	57
NET INCOME	312	6
Net income attributable to noncontrolling interests	0	0
Net income attributable to Chesapeake	312	6
Other Comprehensive Income (Loss), Net of Tax	7	14
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	319	20
Non-Guarantor Subsidiaries	'	'
REVENUES	'	'
Natural gas, oil and NGL	222	128
Marketing, gathering and compression	1	3
Oilfield services	536	554
Total Revenues	759	685
OPERATING EXPENSES	'	'
Natural gas, oil and NGL production	19	11
Production taxes	1	2
Marketing, gathering and compression	1	3
Oilfield services	437	426
General and administrative	26	23
Restructuring and other termination costs	0	2
Natural gas, oil and NGL depreciation, depletion and amortization	62	57
Depreciation and amortization of other assets	74	71
Impairment of natural gas and oil properties	59	91
Impairments of fixed assets and other	20	0
Net gains on sales of fixed assets	1	0
Total Operating Expenses	700	686
INCOME (LOSS) FROM OPERATIONS	59	-1
OTHER INCOME (EXPENSE):	'	'
Interest expense	-21	-16
Losses on investments	0	0
Net gain on sales of investments	0	'
Other income	1	-2
Equity in net earnings of subsidiary	0	0
Total Other Income (Expense)	-20	-18
INCOME (LOSS) BEFORE INCOME TAXES	39	-19
INCOME TAX EXPENSE	15	-7
NET INCOME	24	-12
Net income attributable to noncontrolling interests	0	0
Net income attributable to Chesapeake	24	-12
Other Comprehensive Income (Loss), Net of Tax	0	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	24	-12
Eliminations	'	'
REVENUES	'	'
Natural gas, oil and NGL	-1	3
Marketing, gathering and compression	0	0
Oilfield services	-271	-364
Total Revenues	-272	-361
OPERATING EXPENSES	'	'
Natural gas, oil and NGL production	0	0
Production taxes	0	0
Marketing, gathering and compression	0	0
Oilfield services	-234	-294
General and administrative	0	0
Restructuring and other termination costs	0	0
Natural gas, oil and NGL depreciation, depletion and amortization	-2	0
Depreciation and amortization of other assets	-35	-41
Impairment of natural gas and oil properties	-59	-91
Impairments of fixed assets and other	0	0
Net gains on sales of fixed assets	0	0
Total Operating Expenses	-330	-426
INCOME (LOSS) FROM OPERATIONS	58	65
OTHER INCOME (EXPENSE):	'	'
Interest expense	174	222
Losses on investments	-6	0
Net gain on sales of investments	0	'
Other income	-198	-250
Equity in net earnings of subsidiary	-313	27
Total Other Income (Expense)	-343	-1
INCOME (LOSS) BEFORE INCOME TAXES	-285	64
INCOME TAX EXPENSE	10	14
NET INCOME	-295	50
Net income attributable to noncontrolling interests	-41	-44
Net income attributable to Chesapeake	-336	6
Other Comprehensive Income (Loss), Net of Tax	0	0
COMPREHENSIVE INCOME ATTRIBUTABLE TO CHESAPEAKE	($336)	$6

Condensed_Consolidating_Statem1

Condensed Consolidating Statements Of Cash Flows (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	$1,291	$924
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Acquisitions of proved and unproved properties	-1,084	-1,859
Proceeds from divestitures of proved and unproved properties	49	190
Additions to other property and equipment	-437	-330
Other investing activities	473	254
Net Cash Used In Investing Activities	-999	-1,745
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	421	3,632
Payments on credit facilities borrowings	-362	-2,811
Other financing activities	-184	-254
Intercompany advances, net	0	0
Net Cash Provided By (Used In) Financing Activities	-125	567
Net increase (decrease) in cash and cash equivalents	167	-254
Cash and cash equivalents, beginning of period	837	287
Cash and cash equivalents, end of period	1,004	33
Parent	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Other financing activities	-116	-133
Intercompany advances, net	291	-95
Net Cash Provided By (Used In) Financing Activities	175	-228
Net increase (decrease) in cash and cash equivalents	175	-228
Cash and cash equivalents, beginning of period	799	228
Cash and cash equivalents, end of period	974	0
Guarantor Subsidiaries	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	1,027	790
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Acquisitions of proved and unproved properties	-956	-1,643
Proceeds from divestitures of proved and unproved properties	48	138
Additions to other property and equipment	-319	-186
Other investing activities	442	135
Net Cash Used In Investing Activities	-785	-1,556
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	140	3,395
Payments on credit facilities borrowings	-140	-2,563
Other financing activities	47	-94
Intercompany advances, net	-289	28
Net Cash Provided By (Used In) Financing Activities	-242	766
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	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	264	146
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Acquisitions of proved and unproved properties	-128	-216
Proceeds from divestitures of proved and unproved properties	1	52
Additions to other property and equipment	-118	-144
Other investing activities	5	74
Net Cash Used In Investing Activities	-240	-234
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	281	237
Payments on credit facilities borrowings	-222	-248
Other financing activities	-45	6
Intercompany advances, net	-2	67
Net Cash Provided By (Used In) Financing Activities	12	62
Net increase (decrease) in cash and cash equivalents	36	-26
Cash and cash equivalents, beginning of period	39	59
Cash and cash equivalents, end of period	75	33
Eliminations	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
Net Cash Provided By Operating Activities	0	-12
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Acquisitions of proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	26	45
Net Cash Used In Investing Activities	26	45
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Other financing activities	-70	-33
Intercompany advances, net	0	0
Net Cash Provided By (Used In) Financing Activities	-70	-33
Net increase (decrease) in cash and cash equivalents	-44	0
Cash and cash equivalents, beginning of period	-1	0
Cash and cash equivalents, end of period	($45)	$0

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details) (Senior Notes)	Mar. 31, 2014
Senior Notes	'
Condensed Financial Statements, Captions [Line Items]	'
Noncontrolling Interest, Ownership Percentage by Parent	100.00%

Subsequent_Events_Narrative_De

Subsequent Events - Narrative (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Apr. 11, 2014

Mar. 31, 2014

Apr. 25, 2014

Apr. 24, 2014

Apr. 24, 2014

Apr. 24, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Apr. 24, 2014

Mar. 31, 2014

Mar. 31, 2014

Dec. 31, 2013

Apr. 25, 2014

Apr. 24, 2014

Apr. 10, 2014

In Millions, unless otherwise specified

Compressor [Member]

Compressor [Member]

6.875% Senior Notes Due 2018

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Compressor

Subsequent Event [Member]

Subsequent Event [Member]

Subsequent Event [Member]

Floating Rate Senior Notes due Two Thousand Nineteen [Member]

4.875% Senior Notes Due 2022 [Member]

4.875% Senior Notes Due 2022 [Member]

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

6.875% Senior Notes Due 2018

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

9.5% Senior Notes Due 2015

Compressor

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 [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equipment, Number of Units

'

'

102

337

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Sale of Property, Plant, and Equipment

'

'

'

$362

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

12,969

12,886

'

'

'

'

3,000

1,500

1,500

'

97

97

'

'

1,265

1,265

'

319

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

6.63%

'

'

'

'

4.88%

6.88%

'

'

6.88%

9.50%

'

'

'

9.50%

Proceeds from Issuance of Long-term Debt

'

'

'

'

'

2,966

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

97

'

'

'

'

'

'

Repayments of Notes Payable

'

'

'

'

'

$946

'

'

'

'

'

'

'

'

'

'

$946

'

'