Chesapeake Energy (CHK) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 21, 2014
Document and Entity Information [Abstract]	'	'
Document Type	'10-K	'
Amendment Flag	'false	'
Document Period End Date	31-Dec-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'FY	'
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	'	666,212,515
Entity Well-known Seasoned Issuer	'Yes	'
Entity Voluntary Filers	'No	'
Entity Current Reporting Status	'Yes	'
Entity Public Float	$13.60	'

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$837	$287
Restricted cash	75	111
Accounts receivable, net	2,222	2,245
Short-term derivative assets	0	58
Deferred income tax asset	223	90
Other current assets	299	153
Current assets held for sale	0	4
Total Current Assets	3,656	2,948
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)	56,157	50,172
Unproved properties	12,013	14,755
Oilfield services equipment	2,192	2,130
Other property and equipment	3,203	3,778
Total Property and Equipment, at Cost	73,565	70,835
Less: accumulated depreciation, depletion and amortization (($168) and ($58) attributable to our VIE)	-37,161	-34,302
Property and equipment held for sale, net	730	634
Total Property and Equipment, Net	37,134	37,167
LONG-TERM ASSETS:	'	'
Investments	477	728
Long-term derivative assets	4	2
Other long-term assets	511	766
TOTAL ASSETS	41,782	41,611
CURRENT LIABILITIES:	'	'
Accounts payable	1,596	1,710
Short-term derivative liabilities ($5 and $4 attributable to our VIE)	208	105
Accrued interest	200	226
Current maturities of long-term debt, net	0	463
Other current liabilities ($22 and $21 attributable to our VIE)	3,511	3,741
Current liabilities held for sale	0	21
Total Current Liabilities	5,515	6,266
LONG-TERM LIABILITIES:	'	'
Long-term debt, net	12,886	12,157
Deferred income tax liabilities	3,407	2,807
Long-term derivative liabilities ($0 and $3 attributable to our VIE)	445	934
Asset retirement obligations	405	375
Other long-term liabilities	984	1,176
Total Long-Term Liabilities	18,127	17,449
Chesapeake Stockholders’ Equity:	'	'
Preferred stock, $0.01 par value, 20,000,000 shares authorized:	3,062	3,062
Common stock, $0.01 par value, 1,000,000,000 shares authorized:	7	7
Paid-in capital	12,446	12,293
Retained earnings	688	437
Accumulated other comprehensive loss	-162	-182
Less: treasury stock, at cost; 2,002,029 and 2,147,724 common shares	-46	-48
Total Chesapeake Stockholders’ Equity	15,995	15,569
Noncontrolling interests	2,145	2,327
Total Equity	18,140	17,896
TOTAL LIABILITIES AND EQUITY	$41,782	$41,611

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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	666,192,371	666,467,664
Treasury stock, shares	2,002,029	2,147,724
Variable Interest Entities	'	'
Cash and cash equivalents attributable to our VIEs	$1	$1
Evaluated natural gas and oil properties attributable to our VIEs	488	488
Less:accumulated depreciation, depletion and amortization attributable to our VIEs	-168	-58
Short-term derivative liabilities attributable to our VIEs	5	4
Other current liabilities attributable to our VIEs	22	21
Long-term derivative liabilities attributable to our VIEs	$0	$3

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES:	'	'	'
Natural gas, oil and NGL	$7,052	$6,278	$6,024
Marketing, gathering and compression	9,559	5,431	5,090
Oilfield services	895	607	521
Total Revenues	17,506	12,316	11,635
OPERATING EXPENSES:	'	'	'
Natural gas, oil and NGL production	1,159	1,304	1,073
Production taxes	229	188	192
Marketing, gathering and compression	9,461	5,312	4,967
Oilfield services	736	465	402
General and administrative	457	535	548
Restructuring and other termination costs	248	7	0
Natural gas, oil and NGL depreciation, depletion and amortization	2,589	2,507	1,632
Depreciation and amortization of other assets	314	304	291
Impairment of natural gas and oil properties	0	3,315	0
Impairments of fixed assets and other	546	340	46
Net gains on sales of fixed assets	-302	-267	-437
Total Operating Expenses	15,437	14,010	8,714
INCOME (LOSS) FROM OPERATIONS	2,069	-1,694	2,921
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	-227	-77	-44
Earnings (losses) on investments	-226	-103	156
Gains (losses) on sales of investments	-7	1,092	0
Losses on purchases of debt and extinguishment of other financing	-193	-200	-176
Other income	26	8	23
Total Other Income (Expense)	-627	720	-41
INCOME (LOSS) BEFORE INCOME TAXES	1,442	-974	2,880
INCOME TAX EXPENSE (BENEFIT):	'	'	'
Current income taxes	22	47	13
Deferred income taxes	526	-427	1,110
Total Income Tax Expense (Benefit)	548	-380	1,123
NET INCOME (LOSS)	894	-594	1,757
Net income attributable to noncontrolling interests	-170	-175	-15
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	724	-769	1,742
Preferred stock dividends	-171	-171	-172
Premium on purchase of preferred shares of a subsidiary	-69	0	0
Earnings allocated to participating securities	-10	0	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$474	($940)	$1,570
EARNINGS (LOSS) PER COMMON SHARE:	'	'	'
Basic	$0.73	($1.46)	$2.47
Diluted	$0.73	($1.46)	$2.32
CASH DIVIDEND DECLARED PER COMMON SHARE	$0.35	$0.35	$0.34
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):	'	'	'
Basic	653	643	637
Diluted	653	643	752

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]	'	'	'
NET INCOME (LOSS)	$894	($594)	$1,757
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:	'	'	'
Unrealized gain on derivative instruments, net of income tax expense of $1 million, $4 million and $137 million	2	6	224
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	20	-17	-225
Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net	0	0	4
Unrealized loss on investments, net of income tax benefit of ($4) million, ($4) million and ($1) million	-6	-5	-1
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	4	0	0
Other Comprehensive Income (Loss)	20	-16	2
COMPREHENSIVE INCOME (LOSS)	914	-610	1,759
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	-170	-175	-15
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$744	($785)	$1,744

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrealized gain on derivative instruments, net of income tax expense of $1 million, $4 million and $137 million	$1	$4	$137
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $12 million, ($10) million and ($139) million	12	-10	-139
Ineffective portion of derivatives designated as cash flow hedges, net of income tax expense of $0, $0 and $3 million	0	0	3
Unrealized loss on investments, net of income tax benefit of ($4) million, ($4) million and ($1) million	-4	-4	-1
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of $3 million, $0 and $0	$3	$0	$0

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'	'
NET INCOME (LOSS)	$894	($594)	$1,757
ADJUSTMENTS TO RECONCILE NET INCOME (LOSS) TO CASH PROVIDED BY OPERATING ACTIVITIES:	'	'	'
Depreciation, depletion and amortization	2,903	2,811	1,923
Deferred income tax expense (benefit)	526	-427	1,110
Derivative gains, net	-71	-926	-751
Cash (payments) receipts on derivative settlements, net	-106	226	725
Stock-based compensation	98	120	153
Net gains on sales of fixed assets	-302	-267	-437
Impairment of natural gas and oil properties	0	3,315	0
Impairments of fixed assets and other	483	316	46
(Gains) losses on investments	229	164	-41
(Gains) losses on sales of investments	7	-1,092	0
Losses on purchases of debt and extinguishment of other financing	40	200	5
Restructuring and other termination costs	175	2	0
Other	80	72	-3
(Increase) decrease in accounts receivable and other assets	5	-68	-530
Increase (decrease) in accounts payable, accrued liabilities and other	-347	-1,015	1,946
Net Cash Provided By Operating Activities	4,614	2,837	5,903
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Drilling and completion costs	-5,604	-8,930	-7,467
Acquisitions of proved and unproved properties	-1,032	-3,161	-4,974
Proceeds from divestitures of proved and unproved properties	3,467	5,884	7,651
Additions to other property and equipment	-972	-2,651	-2,009
Proceeds from sales of other assets	922	2,492	1,312
Proceeds from (additions to) investments	-44	-395	101
Proceeds from sales of investments	115	2,000	0
Acquisition of drilling company	0	0	-339
(Increase) decrease in restricted cash	177	-222	-44
Other	4	-1	-43
Net Cash Used In Investing Activities	-2,967	-4,984	-5,812
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	7,669	20,318	15,509
Payments on credit facilities borrowings	-7,682	-21,650	-17,466
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263	1,614
Proceeds from issuance of term loans, net of discount and offering costs	0	5,722	0
Repayments of Long-term Debt	-2,141	-4,000	-2,015
Cash paid for common stock dividends	-233	-227	-207
Cash paid for preferred stock dividends	-171	-171	-172
Cash paid on financing derivatives	-91	-37	1,043
Cash paid to extinguish other financing	-141	0	0
Cash paid for prepayment of mortgage	-55	0	0
Proceeds from sales of noncontrolling interests	6	1,077	1,348
Proceeds from other financings	0	257	300
Cash paid to purchase preferred shares of a subsidiary	-212	0	0
Distributions to noncontrolling interest owners	-215	-218	-9
Other	-105	-251	213
Net Cash Provided By (Used In) Financing Activities	-1,097	2,083	158
Net increase (decrease) in cash and cash equivalents	550	-64	249
Cash and cash equivalents, beginning of period	287	351	102
Cash and cash equivalents, end of period	837	287	351
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'	'
Interest, net of capitalized interest	-43	0	0
Income taxes, net of refunds received	26	44	-25
Change in accrued drilling and completion costs	-63	-75	176
Change in accrued acquisitions of proved and unproved properties	-1	242	81
Change in accrued additions to other property and equipment	($81)	($25)	$64

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Common Stock

Common Stock

Common Stock

Paid-In Capital

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

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]

Accumulated Other Comprehensive Income (Loss) [Member]

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Parent

Parent

Parent

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

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

'

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'

Balance, beginning of period

'

'

'

$3,062

$3,062

$3,062

$3,065

$7

$7

$7

'

'

'

$12,446

$12,293

$12,146

$12,194

'

'

'

$688

$437

$1,608

$190

'

'

'

($162)

($182)

($166)

($168)

'

'

'

($46)

($48)

($33)

($24)

$15,995

$15,569

$16,624

'

'

'

$2,145

$2,327

$1,337

$0

Conversion of 0,0 and 3,000 shares of preferred stock for common stock

0

0

-3

'

'

'

'

'

'

'

'

'

'

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'

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'

'

'

'

'

'

'

'

Stock-based compensation

'

'

'

'

'

'

'

'

'

'

162

174

171

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'

'

'

'

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'

'

'

'

'

Conversion of preferred stock for 0, 0 and 111,111 shares of common stock

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'

'

'

'

'

'

'

'

0

0

3

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'

'

'

'

'

'

'

Purchase of contingent convertible notes

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'

'

'

'

'

'

'

'

'

0

0

-123

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Offering/transaction expenses

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'

'

'

'

'

'

'

'

0

0

-12

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'

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'

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'

'

'

'

'

'

'

Reduction in tax benefit from stock-based compensation

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'

'

'

'

'

'

'

'

-13

-30

-26

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Dividends on common stock

'

'

'

'

'

'

'

'

'

'

0

0

-48

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'

Dividends on preferred stock

'

'

'

'

'

'

'

'

'

'

0

0

-15

'

'

'

'

-171

-171

-156

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'

'

'

'

'

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'

'

'

'

'

'

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Exercise of stock options

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'

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'

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'

'

4

3

2

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'

Net income (loss) attributable to Chesapeake

'

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'

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'

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'

'

'

'

'

'

'

'

'

724

-769

1,742

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Dividends on common stock

'

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'

'

'

'

'

'

'

-233

-231

-168

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Premium on purchase of preferred shares of a subsidiary

'

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'

'

'

'

'

'

'

-69

0

0

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'

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'

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Hedging activity

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22

-11

3

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Investment activity

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-2

-5

-1

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Purchase of 251,403, 652,443 and 425,140 shares for company benefit plans

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-6

-16

-11

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Release of 397,098, 57,252 and 93,906 shares from company benefit plans

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8

1

2

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Sales of noncontrolling interests

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6

1,077

1,340

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'

'

Net income attributable to noncontrolling interests

'

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'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

170

175

15

'

'

'

'

Distributions to noncontrolling interest owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-215

-218

-18

'

'

'

'

Deconsolidation of investments, net

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

-44

0

'

'

'

'

Purchase of preferred shares of a subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-143

0

0

'

'

'

'

Balance, end of period

'

'

'

$3,062

$3,062

$3,062

$3,065

$7

$7

$7

'

'

'

$12,446

$12,293

$12,146

$12,194

'

'

'

$688

$437

$1,608

$190

'

'

'

($162)

($182)

($166)

($168)

'

'

'

($46)

($48)

($33)

($24)

$15,995

$15,569

$16,624

'

'

'

$2,145

$2,327

$1,337

$0

CONSOLIDATED_STATEMENTS_OF_STO1

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Treasury Stock - Common	'	'	'
Purchase of shares for company benefit plans, shares	251,403	652,443	425,140
Release of shares from company benefit plans, shares	397,098	57,252	93,906
Preferred Stock	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	0	0	3,000
Paid-In Capital	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	0	0	111,111

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies (Note)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

'

Organization, Consolidation, Basis of Presentation, Business Description and Accounting Policies [Text Block]

'

Basis of Presentation and Summary of Significant Accounting Policies

Description of Company

Chesapeake Energy Corporation ("Chesapeake" or the "Company") is a natural gas and oil exploration and production company engaged in the acquisition, exploration and development of properties for the production of natural gas, oil and natural gas liquids (NGL) from underground reservoirs. We also own substantial marketing, compression and other oilfield services businesses. Our operations are located onshore in the U.S.

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake 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.

Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of natural gas and oil reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates.

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment in common stock. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 13 for further discussion of our investments. Undivided interests in natural gas and oil exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both the consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 14 for further discussion of VIEs.

Risks and Uncertainties

We have recently conducted a company-wide review of our operations, assets and organizational structure to best position the Company to maximize shareholder value going forward 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.

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Restricted cash consists of balances required to be maintained by the terms of the respective agreements governing the activities of CHK Utica, L.L.C. (CHK Utica) and CHK Cleveland Tonkawa, L.L.C. (CHK C-T). See Note 8 for further discussion of these entities.

Accounts Receivable

Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe will be uncollectible. During 2013, 2012 and 2011, we recognized $2 million, a nominal amount and $1 million of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2013 and 2012 are detailed below.

December 31,

2013

2012

($ in millions)

Natural gas, oil and NGL sales

$

1,548

$

1,457

Joint interest

417

592

Oilfield services

63

24

Related parties(a)

62

23

Other

150

168

Allowance for doubtful accounts

(18

)

(19

)

Total accounts receivable, net

$

2,222

$

2,245

___________________________________________

(a)

See Note 7 for discussion of related party transactions.

Natural Gas and Oil Properties

Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. Estimates of our proved reserves as of December 31, 2013 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 81% of these proved reserves estimates (by volume) as of December 31, 2013 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of natural gas and oil properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2013 and the year in which the associated costs were incurred.

Year of Acquisition

2013

2012

2011

Prior

Total

($ in millions)

Leasehold acquisition cost

$

229

$

1,648

$

2,113

$

5,066

$

9,056

Exploration cost

623

341

93

8

1,065

Capitalized interest

667

516

270

439

1,892

Total

$

1,519

$

2,505

$

2,476

$

5,513

$

12,013

We also review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for natural gas and oil derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of natural gas, oil and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2013, none of our open derivative instruments were designated as cash flow hedges. Our natural gas and oil hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and natural gas, oil and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is written off as an expense.

We account for seismic costs as part of our natural gas and oil properties (i.e., full cost pool). Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. Such costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Other Property and Equipment

Other property and equipment consists primarily of oilfield services equipment, including drilling rigs, rental tools and hydraulic fracturing equipment, natural gas compressors, buildings and improvements, land, vehicles, office equipment, natural gas and oil gathering systems and treating plants. Substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 15. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 15 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2013, 2012 and 2011, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 16 for further discussion of these impairments.

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill of $43 million as of December 31, 2013 and 2012 consisted of the excess consideration over the fair value of assets acquired of $28 million in our Bronco Drilling Company acquisition and $15 million in our Horizon Drilling Services acquisition. Quoted market prices are not available for these reporting units and their fair values are based upon several valuation analyses, including discounted cash flows. We performed annual impairment tests of goodwill in the fourth quarters of 2013 and 2012. Based on these assessments, no impairment of goodwill was required. Goodwill is included in our oilfield services segment.

Accounts Payable

Included in accounts payable as of December 31, 2013 and 2012 are liabilities of approximately $397 million and $432 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, term loan, revolving bank credit facilities and hedging facility. The remaining unamortized issuance costs as of December 31, 2013 and 2012 totaled $145 million and $182 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations

We recognize liabilities for retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 19 for further discussion of asset retirement obligations.

Revenue Recognition

Natural Gas, Oil and NGL Sales. Revenue from the sale of natural gas, oil and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance liability net position as of December 31, 2013 and 2012 was $11 million and $9 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the natural gas, oil and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. Chesapeake's results of operations related to its natural gas, oil and NGL marketing activities are presented on a "gross" basis, because we act as a principal rather than an agent. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Our oilfield services operating segment is responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties.

•

Drilling. Revenues are generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services are recognized over the days of actual mobilization.

•

Hydraulic Fracturing. Revenue is recognized upon the completion of each fracturing stage. Typically one or more fracturing stages per day per active crew is completed during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

•

Oilfield Rentals. Oilfield equipment rentals include drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services include air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services are priced by the day or hour based on the type of equipment being rented and the service job performed. Revenue is recognized ratably over the term of the rental.

•

Oilfield Trucking. Oilfield trucking provides rig relocation and logistics services as well as fluid handling services. Trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transport produced water from the wellsites. These services are priced on a per barrel basis based on mileage and revenue is recognized as services are performed.

•

Other Operations. A manufacturing subsidiary designs, engineers and fabricates natural gas compressor packages that are purchased primarily by Chesapeake. Compression units are priced based on certain specifications such as horsepower, stages and additional options. Revenue is recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Derivatives

Derivative instruments are recorded on the consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge effectiveness and are recognized currently in earnings.

We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in the consolidated statements of operations within natural gas, oil and NGL sales and interest expense, respectively. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of natural gas and oil leasehold and exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are recognized as general and administrative expenses, natural gas, oil and NGL production expenses, marketing, gathering and compression expenses or oilfield services expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2011 to conform to the presentation used for the 2013 consolidated financial statements.

Earnings_Per_Share_Note

Earnings Per Share (Note)	12 Months Ended
	Dec. 31, 2013
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 years ended December 31, 2013, 2012 and 2011, 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 years ended December 31, 2013 and 2012, 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 these two years. 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 2013 and 2012:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Year Ended December 31, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	10	5
	Year Ended December 31, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	—	5
	For the year ended December 31, 2011, 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 year ended December 31, 2011 is as follows:
		Income (Numerator)		Weighted	Per
				Average	Share
				Shares	Amount
				(Denominator)
		(in millions, except per share data)
	For the Year Ended December 31, 2011:
	Basic EPS	$	1,570	637	$	2.47
	Effect of Dilutive Securities:
	Assumed conversion as of the beginning of the period
	of preferred shares outstanding during the period:
	Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		55
	Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		39
	Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	11		5
	Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
	Participating securities	—		9
	Outstanding stock options	—		1
	Diluted EPS	$	1,742	752	$	2.32

Debt_Note

Debt (Note)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Debt Disclosure [Text Block]	'
	Debt
	Our long-term debt consisted of the following as of December 31, 2013 and 2012:
			December 31,
			2013				2012
			($ in millions)
	Term loan due 2017		$	2,000			$	2,000
	7.625% senior notes due 2013		—				464
	9.5% senior notes due 2015		1,265				1,265
	3.25% senior notes due 2016		500				—
	6.25% euro-denominated senior notes due 2017(a)		473				454
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018		97				474
	7.25% senior notes due 2018		669				669
	6.625% senior notes due 2019(b)		650				650
	6.775% senior notes due 2019		—				1,300
	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				—
	5.75% senior notes due 2023		1,100				—
	2.75% contingent convertible senior notes due 2035(c)		396				396
	2.5% contingent convertible senior notes due 2037(c)		1,168				1,168
	2.25% contingent convertible senior notes due 2038(c)		347				347
	Corporate revolving bank credit facility		—				—
	Oilfield services revolving bank credit facility		405				418
	Discount on senior notes and term loan(d)		(357		)		(465		)
	Interest rate derivatives(e)		13				20
	Total debt, net		12,886				12,620
	Less current maturities of long-term debt, net(f)		—				(463		)
	Total long-term debt, net		$	12,886			$	12,157
	___________________________________________
	(a)	The principal amount shown is based on the exchange rate of $1.3743 to €1.00 and $1.3193 to €1.00 as of December 31, 2013 and 2012, respectively. See Note 11 for information on our related foreign currency derivatives.
	(b)	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.
	(c)	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 fourth quarter of 2013, 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 first 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 2013, 2012 or 2011. 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. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years under certain conditions. 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
	(d)	Discount as of December 31, 2013 and 2012 included $303 million and $376 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million and $40 million as of December 31, 2013 and 2012, respectively, associated with our term loan discussed further below.
	(e)	See Note 11 for further discussion related to these instruments.
	(f)	As of December 31, 2012, there was $1 million of discount associated with the 7.625% Senior Notes due 2013.
	Total principal amount of debt maturities, using the earliest conversion date for contingent convertible senior notes, for the five years ended after December 31, 2013 are as follows:
			Principal Amount
			of Debt Securities
			($ in millions)
	2014		$	—
	2015		1,661
	2016		905
	2017		4,301
	2018		1,113
	2019 and thereafter		5,250
	Total		$	13,230
	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. Our obligations under the facility rank equally with our outstanding senior notes and contingent convertible senior notes and are unconditionally guaranteed on a joint and several basis by our direct and indirect wholly owned subsidiaries that are subsidiary guarantors under the indentures for such notes. Amounts borrowed under the facility bear interest at our option, at either (i) the Eurodollar rate, which is based on the London Interbank Offered Rate (LIBOR), plus a margin of 4.50% or (ii) a base rate equal to the greater of (a) the Bank of America, N.A. prime rate, (b) the federal funds effective rate plus 0.50% per annum and (c) the Eurodollar rate that would be applicable to a Eurodollar loan with an interest period of one month plus 1% per annum, in each case, plus a margin of 3.50%. The Eurodollar rate is subject to a floor of 1.25% per annum, and the base rate is subject to a floor of 2.25% per annum. Interest is payable quarterly or, if the Eurodollar rate applies, it may be payable at more frequent intervals.
	The term loan matures on December 2, 2017 and may be voluntarily repaid before November 9, 2015 at par plus a specified premium and at any time thereafter at par. The term loan may also be refinanced or amended to extend the maturity date at our option, subject to lender approval.
	The term loan credit agreement contains negative covenants substantially similar to those contained in the Company’s corporate revolving bank credit facility, including covenants that limit our ability to incur indebtedness, grant liens, make investments, loans and restricted payments and enter into certain business combination transactions. Other covenants include additional restrictions regarding the incurrence of certain unsecured indebtedness, the incurrence of secured indebtedness, the disposition of assets and the prepayment of certain indebtedness. The term loan credit agreement does not contain financial maintenance covenants.
	We were in compliance with all covenants under the term loan credit agreement as of December 31, 2013. If we should fail to perform our obligations under the agreement, the term loan could be terminated and any outstanding borrowings under the term loan credit agreement could be declared immediately due and payable. The term loan credit agreement also has cross default provisions that apply to other indebtedness of Chesapeake and its restricted subsidiaries with an outstanding principal amount in excess of $125 million.
	In 2012, we used the proceeds from the term loan, along with proceeds from asset sales, to repay our $4.0 billion term loan credit facility established in May 2012. We recorded $200 million of losses associated with the repayment, including $86 million of unamortized deferred charges and $114 million of unamortized debt discount.
	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 21 for 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.
During 2013, we issued $2.3 billion in aggregate principal amount of senior notes at par in a registered public offering. The offering included three series of notes: $500 million in aggregate principal amount of 3.25% Senior Notes due 2016; $700 million in aggregate principal amount of 5.375% Senior Notes due 2021; and $1.1 billion in aggregate principal amount of 5.75% Senior Notes due 2023. We used a portion of the net proceeds of $2.274 billion to repay outstanding indebtedness under our corporate revolving bank credit facility and to purchase $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers. We recorded a loss of approximately $37 million associated with the tender offers, including $32 million in premiums and $5 million of unamortized deferred charges. During the third quarter of 2013, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.
During 2012, we issued $1.3 billion in aggregate principal amount of our 6.775% Senior Notes due 2019 (the “2019 Notes”) in a registered public offering. We used the net proceeds of $1.263 billion from the offering to repay outstanding indebtedness under our corporate revolving bank credit facility. On May 13, 2013, we redeemed the 2019 Notes at par pursuant to notice of special early redemption. We recorded a loss of approximately $33 million associated with the redemption, including $19 million of unamortized deferred charges and $14 million of discount. As described in the following paragraph, the special early redemption was the subject of litigation.
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.
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 $50 million or more.
Under a registration rights agreement, we agreed to file a registration statement enabling holders of the COO senior notes to exchange the privately placed COO senior notes for publicly registered notes with substantially the same terms. The exchange offer was completed in July 2013.
Bank Credit Facilities
During 2013, we had the following two revolving bank credit facilities as sources of liquidity:
		Corporate				Oilfield Services
		Credit Facility(a)				Credit Facility(b)
		($ 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 December 31, 2013		$	—			$	405
Letters of credit outstanding as of December 31, 2013		$	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 December 31, 2013.
In September 2012, we entered into an amendment to the credit facility agreement, effective September 30, 2012. The amendment, among other things, adjusted our required indebtedness to EBITDA ratio through the earlier of (i) December 31, 2013 and (ii) the date on which we elected to reinstate the indebtedness to EBITDA ratio in effect prior to the amendment (in either case, the “Amendment Effective Period”). The credit facility amendment also increased the applicable margin by 0.25% for borrowings during the Amendment Effective Period when credit extensions exceeded 50% of the borrowing capacity. The amendment did not allow our collateral value securing the borrowings to be more than $75 million below the collateral value that was in effect as of September 30, 2012 during the Amendment Effective Period. During the Amendment Effective Period, the amendment increased the maximum indebtedness to EBITDA ratio to 6.00 to 1.00 as of September 30, 2012, 5.00 to 1.00 as of December 31, 2012 and 4.75 to 1.00 as of March 31, 2013. On June 28, 2013, we elected to reinstate the indebtedness to EBITDA ratio to 4.00 to 1.00, which was the ratio in effect prior to the amendment.
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 December 31, 2013. 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.

Contingencies_and_Commitments_

Contingencies and Commitments (Note)	12 Months Ended
	Dec. 31, 2013
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 an indeterminate amount of damages. 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. 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.
	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 is continuing as an investigation. The Company is providing 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.
	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, including a subpoena issued by the Michigan Department of Attorney General relating to its investigation of possible violations of that state’s criminal solicitation law.
	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 set 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, also lodged on December 19, 2013, is subject to court approval.
	The consent decree requires CALLC to pay a civil penalty of approximately $3 million, to be 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. Eleven of the sites covered by the consent decree were subject to orders for compliance issued by the EPA in 2010 and 2011. Since then, CALLC has been correcting the alleged violations and restoring those sites in compliance with EPA’s orders. The settlement resolves alleged violations of both the CWA and state law.
	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 has fully restored the site. 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, Compressor and Other Operating Leases
	As of December 31, 2013, we leased 45 rigs under master lease agreements with an aggregate undiscounted future lease commitment of $76 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. During 2013, we purchased 23 leased rigs from various lessors for an aggregate purchase price of approximately $141 million and paid approximately $22 million in lease termination costs. Through these transactions, we lowered our minimum aggregate undiscounted future rig lease payments by approximately $142 million. See Note 23 for further discussion related to additional leased rigs purchased subsequent to December 31, 2013.
	As of December 31, 2013, we leased 1,781 compressors under master lease agreements with an aggregate undiscounted future lease commitment of $260 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. During 2013, we purchased 541 leased compressor units from various lessors for an aggregate purchase price of approximately $97 million, lowering our minimum aggregate undiscounted future compressor lease payments by approximately $73 million. See Note 23 for further discussion related to additional leased compressors purchased subsequent to December 31, 2013.
	Future operating lease commitments related to rigs, compressors and other equipment or property are not recorded in the accompanying consolidated balance sheets. The aggregate undiscounted minimum future lease payments are presented below.
		December 31, 2013
		Rigs		Compressors		Other		Total
		($ in millions)
	2014	$	51	$	53	$	13	$	117
	2015	11		50		11		72
	2016	6		104		9		119
	2017	7		23		3		33
	2018	1		29		2		32
	After 2018	—		1		1		2
	Total	$	76	$	260	$	39	$	375
	Rent expense for rigs, compressors and other equipment, including short-term rentals, for the years ended December 31, 2013, 2012 and 2011 was $158 million, $185 million and $184 million, respectively.
	Gathering, Processing and Transportation Agreements
	We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying consolidated balance sheets; however, they are reflected as adjustments to natural gas, oil and NGL sales prices used in our proved reserves estimates.
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, are presented below.
		December 31, 2013
		($ in millions)
	2014	$	2,002
	2015	1,829
	2016	1,921
	2017	1,948
	2018	1,762
	2019 - 2099	7,728
	Total	$	17,190
	Drilling Contracts
	Chesapeake has contracts with various drilling contractors to utilize approximately eight rigs with terms ranging from six months to three years. These commitments are not recorded in the accompanying consolidated balance sheets. As of December 31, 2013, the aggregate undiscounted minimum future payments under these drilling rig commitments are presented below:
		December 31,
		2013
		($ in millions)
	2014	$	36
	2015	5
	Total	$	41
	In December 2013, we terminated a drilling contract prior to the end of its term and recognized a $15 million charge that is included in impairments of fixed assets and other in our consolidated statement of operations.
	Drilling Commitments
	In December 2011, as part of our Utica joint venture development agreement with Total S.A. (Total) (see Note 12), 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 December 31, 2013, we had spud 423 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 8 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 December 31, 2013, we had $30 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 12 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 12), 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 had an estimated shortfall of approximately 13,000 net acres pursuant to our net acreage maintenance commitment with Total under the terms of our Barnett Shale joint venture agreement as of the December 31, 2012 measurement date and recorded a $26 million charge in impairments of fixed assets and other in our consolidated statement of operations. We revised our estimate of the net acreage shortfall to be approximately 14,000 net acres as of December 31, 2013 and recorded an additional $2 million charge in 2013. 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 the 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 monetary penalties if we do not operate a specific number of COO’s drilling rigs or utilize a specific number of its hydraulic fracturing fleets. As of December 31, 2013, we had recognized a nominal amount for non-utilization pursuant to the agreement and eliminated its impact in consolidation.
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.
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 12 for further discussion of our VPP transactions.

Other_Liabilities_Note

Other Liabilities (Note)	12 Months Ended
	Dec. 31, 2013
Other Liabilities Disclosure [Abstract]	'
Other Liabilities Disclosure [Text Block]	'
	Other Liabilities
	Other current liabilities as of December 31, 2013 and 2012 are detailed below.
			December 31,
			2013		2012
			($ in millions)
	Revenues and royalties due others		$	1,409	$	1,337
	Accrued natural gas, oil and NGL drilling and production costs		457		525
	Joint interest prepayments received		464		749
	Accrued compensation and benefits		320		225
	Other accrued taxes		161		130
	Accrued dividends		101		101
	Other		599		674
	Total other current liabilities		$	3,511	$	3,741
	Other long-term liabilities as of December 31, 2013 and 2012 are detailed below.
			December 31,
			2013		2012
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	250	$	275
	CHK C-T ORRI conveyance obligation(b)		149		164
	Financing obligations(c)		31		175
	Mortgages payable(d)		—		56
	Other		554		506
	Total other long-term liabilities		$	984	$	1,176
	____________________________________________
	(a)	$13 million and $18 million of the total $263 million and $293 million obligations are recorded in other current liabilities as of December 31, 2013 and December 31, 2012, respectively. See Note 8 for further discussion of the transaction.
	(b)	$12 million and $14 million of the total $161 million and $178 million obligations are recorded in other current liabilities as of December 31, 2013 and December 31, 2012, respectively. See Note 8 for further discussion of the transaction.
	(c)	As of December 31, 2012, this amount consisted primarily of an obligation related to 111 real estate surface properties in the Fort Worth, Texas area that we financed in 2009 for approximately $145 million and for which we entered into a 40-year master lease agreement whereby we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the consolidated balance sheet. On November 1, 2013, we terminated the financing master lease agreement on the surface properties for $258 million and recorded a loss of approximately $123 million associated with the extinguishment.
	(d)	In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of approximately $54 million with a five-year term loan which had a floating interest rate of prime plus 275 basis points. In 2013, we prepaid the term loan in full without penalty. As of December 31, 2013, the building was classified as property and equipment held for sale on our consolidated balance sheet.

Income_Taxes_Notes

Income Taxes (Notes)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Income Tax Disclosure [Text Block]	'
	Income Taxes
	The components of the income tax provision (benefit) for each of the periods presented below are as follows:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Current
	Federal	$	—		$	—		$	—
	State	22			47			13
		22			47			13
	Deferred
	Federal	502			(358		)	1,044
	State	24			(69		)	66
		526			(427		)	1,110
	Total	$	548		$	(380	)	$	1,123
	The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Income tax expense (benefit) at the federal statutory rate (35%)	$	505		$	(341	)	$	1,008
	State income taxes (net of federal income tax benefit)	38			(38		)	74
	Other	5			(1		)	41
	Total	$	548		$	(380	)	$	1,123
	Deferred income taxes are provided to reflect temporary differences in the basis of net assets for income tax and financial reporting purposes. The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
		Years Ended December 31,
		2013			2012
		($ in millions)
	Deferred tax liabilities:
	Natural gas and oil properties	$	(2,631	)	$	(1,999	)
	Other property and equipment	(371		)	(436		)
	Volumetric production payments	(1,216		)	(1,432		)
	Contingent convertible debt	(439		)	(416		)
	Deferred tax liabilities	(4,657		)	(4,283		)
	Deferred tax assets:
	Net operating loss carryforwards	535			711
	Derivative instruments	108			172
	Asset retirement obligations	153			142
	Investments	130			106
	Deferred stock compensation	66			47
	Accrued liabilities	120			90
	Noncontrolling interest liabilities	152			178
	Alternative minimum tax credits	317			225
	Other	40			55
	Deferred tax assets	1,621			1,726
	Valuation allowance	(148		)	(160		)
	Net deferred tax assets	1,473			1,566
	Net deferred tax assets (liabilities)	$	(3,184	)	$	(2,717	)
	Reflected in accompanying balance sheets as:
	Current deferred income tax asset	$	223		$	90
	Non-current deferred income tax liability	(3,407		)	(2,807		)
	Total	$	(3,184	)	$	(2,717	)
	As of December 31, 2013 and 2012, we classified $223 million and $90 million, respectively, of deferred tax assets as current that were attributable to current temporary differences associated with accrued liabilities, derivative liabilities and other items. As of December 31, 2013 and 2012, non-current deferred tax liabilities on the consolidated balance sheets that were primarily attributable to temporary differences associated with oil and gas properties and volumetric production payments were $3.407 billion and $2.807 billion, respectively.
	Deferred tax assets relating to tax benefits of employee share-based compensation have been reduced for stock options exercised and restricted stock that vested in periods in which Chesapeake was in a net operating loss (NOL) position. Some exercises and vestings result in tax deductions in excess of previously recorded benefits based on the stock option or restricted stock value at the time of grant (windfalls). Although these additional tax benefits or windfalls are reflected in NOL carryforwards in the tax return, the additional tax benefit associated with the windfalls is not recognized until the deduction reduces taxes payable pursuant to accounting for stock compensation under U.S. GAAP. Accordingly, since the tax benefit does not reduce Chesapeake's current taxes payable due to NOL carryforwards, these windfall tax benefits are not reflected in Chesapeake's NOLs in deferred tax assets. Windfalls included in NOL carryforwards but not reflected in deferred tax assets as of December 31, 2013 totaled $24 million. Any shortfalls resulting from tax deductions that were less than the previously recorded benefits were recorded as reductions to additional paid-in capital.
	At December 31, 2013, Chesapeake had federal income tax NOL carryforwards of approximately $592 million and state NOL carryforwards of approximately $7.0 billion (deferred tax assets related to these state NOL carryforwards were $328 million), which excludes the NOL carryforwards related to unrecognized tax benefits and stock compensation windfalls that have not been recognized under U.S. GAAP. Additionally, we had $51 million of alternative minimum tax (AMT) NOL carryforwards, net of unrecognized tax benefits, available as a deduction against future AMT income and $599 million of AMT NOL carrybacks to be used against prior year AMT income. The NOL carryforwards expire from 2025 through 2033. The value of these carryforwards depends on the ability of Chesapeake to generate taxable income. As of December 31, 2013 and 2012, we had deferred tax assets of $1.621 billion and $1.726 billion, respectively, upon which we had a valuation allowance of $148 million and $160 million, respectively, for certain state NOL carryforwards that we have concluded are not more likely than not to be utilized prior to expiration. The net decrease in the valuation allowance of $12 million is reflected as a reduction to the 2013 income tax provision and is due to changes in judgment regarding the future realizability of our state NOL carryforwards.
	The ability of Chesapeake to utilize NOL carryforwards to reduce future federal taxable income and federal income tax is subject to various limitations under the Internal Revenue Code of 1986, as amended (the Code). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the issuance or exercise of rights to acquire stock, the purchase or sale of stock by 5% stockholders, as defined in the Treasury regulations, and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Chesapeake.
	In the event of an ownership change (as defined for income tax purposes), Section 382 of the Code imposes an annual limitation on the amount of a corporation's taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of the corporation multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains (as defined in the Code) inherent in the assets at the time of the ownership change. Certain NOLs acquired through various acquisitions are also subject to limitations.
	The following table summarizes our federal and AMT NOLs as of December 31, 2013 and any related limitations:
		Total			Total Limitation			Annual Limitation
		($ in millions)
	Federal net operating loss	$	592		$	49		$	15
	AMT net operating loss	$	650		$	35		$	15
	As of December 31, 2013, we do not believe that an ownership change has occurred. Future equity transactions by Chesapeake or by 5% stockholders (including relatively small transactions and transactions beyond our control) could cause an ownership change and therefore a limitation on the annual utilization of NOLs.
	Accounting guidance for recognizing and measuring uncertain tax positions prescribes a threshold condition that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. As of December 31, 2013 and 2012, the amount of unrecognized tax benefits related to NOL carryforwards and state tax liabilities associated with uncertain tax positions was $644 million and $599 million, respectively. Of these amounts, $4 million and $1 million, respectively, are related to state tax liabilities while the remainder is related to NOL carryforwards. If these unrecognized tax benefits are disallowed and our NOL carryforwards are reduced, the reduction will be offset by additional tax basis that will generate future deductions. The uncertain tax positions identified would not have a material effect on the effective tax rate. No material changes to the current uncertain tax positions are expected within the next 12 months. As of December 31, 2013 and 2012, we had accrued liabilities of $13 million and $6 million, respectively, for interest related to these uncertain tax positions. Chesapeake recognizes interest related to uncertain tax positions in interest expense. Penalties, if any, related to uncertain tax positions would be recorded in other expenses.
	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
	2013			2012			2011
	($ in millions)
Unrecognized tax benefits at beginning of period	$	599		$	369		$	34
Additions based on tax positions related to the current year	15			134			135
Additions to tax positions of prior years	30			96			200
Settlements	—			—			—
Unrecognized tax benefits at end of period	$	644		$	599		$	369
Chesapeake's federal and state income tax returns are routinely audited by federal and state fiscal authorities. The Internal Revenue Service (IRS) is currently auditing our federal income tax returns for 2007 through 2011. The federal tax returns for 1999 through 2006 remain subject to examination for the purpose of determining the amount of remaining tax NOL and other carryforwards. The 2007 through 2013 years remain open for all purposes of examination by the IRS and other taxing authorities in material jurisdictions.

Related_Party_Note

Related Party (Note)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Related Party Transactions Disclosure [Text Block]	'
	Related Party Transactions
	Former Chief Executive Officer
	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. Since Chesapeake was founded in 1989, Mr. McClendon and his affiliates have acquired working interests in virtually all of our natural gas and oil properties by participating in our drilling activities under the terms of Mr. McClendon’s employment agreements and, since 2005, the Founder Well Participation Program (FWPP). The Company is reimbursed for costs associated with leasehold acquired under the FWPP, and well costs are charged to FWPP interests based on percentage ownership. On April 30, 2012, the Company's Board of Directors and Mr. McClendon agreed to terminate the FWPP 18 months before the end of the 10-year term approved by our shareholders in June 2005. Mr. McClendon has elected to participate in the FWPP through the expiration of the FWPP on June 30, 2014 at the maximum 2.5% working interest permitted, the same participation percentage that Mr. McClendon has elected every year since 2004. The Compensation Committee of the Board of Directors, which administers and interprets the FWPP, is reviewing with the assistance of independent counsel the prior administration of the plan. As of December 31, 2013 and 2012, we had accrued accounts receivable from Mr. McClendon of $62 million and $23 million, respectively, representing FWPP joint interest billings. In conjunction with certain sales of natural gas and oil properties by the Company, affiliates of Mr. McClendon have sold interests in the same properties and on the same terms as those that applied to the interests sold by the Company, and the proceeds were paid to the sellers based on their respective ownership percentages. These interests were acquired through the FWPP.
	On December 31, 2008, we entered into a new five-year employment agreement with Mr. McClendon that contained a one-time well cost incentive award to him. The total cost of the award to Chesapeake was $75 million plus employment taxes in the amount of approximately $1 million. The net incentive award, after deduction of applicable withholding and employment taxes, of approximately $44 million was fully applied against costs attributable to interests in Company wells acquired by Mr. McClendon or his affiliates under the FWPP. The incentive award was subject to a clawback provision equal to any unvested portion of the award if during the initial five-year term of the employment agreement, Mr. McClendon resigned from the Company or was terminated for cause by the Company. We recognized the incentive award as general and administrative expense over the five-year vesting period for the clawback, resulting in an expense of approximately $15 million per year beginning in 2009. The incentive award clawback did not apply to Mr. McClendon’s termination in 2013. See Note 17 for additional information on the terms of his separation from the Company.
	On July 26, 2013, the Company and Mr. McClendon rescinded the December 2008 sale of an antique map collection pursuant to the terms of a settlement agreement terminating pending shareholder litigation that was approved by the District Court of Oklahoma County, Oklahoma on January 30, 2012 and affirmed on appeal. The Company returned the subject maps to Mr. McClendon, and Mr. McClendon paid the Company $12 million plus interest.
	Equity Method Investees
	Other than Mr. McClendon, only our equity method investees were considered related parties. During 2013, 2012 and 2011, we had the following related party transactions with our equity method investees.
			Years Ended December 31,
			2013		2012		2011
			($ in millions)
	Purchases(a)		$	—	$	73	$	—
	Sales(b)		$	666	$	392	$	171
	Services(c)		$	397	$	480	$	369
	___________________________________________
	(a)	Purchase of equipment from FTS.
	(b)	In 2013, 2012 and 2011, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC.
	(c)	Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.
	The table below shows the total related party amounts due from and due to our equity method investees.
			December 31,
			2013		2012		2011
			($ in millions)
	Amounts due from equity method investment related parties		$	47	$	67	$	29
	Amounts due to equity method investment related parties		$	1	$	42	$	115

Equity_Note

Equity (Note)	12 Months Ended
	Dec. 31, 2013
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 2013, 2012 and 2011:
			Years Ended December 31,
			2013			2012			2011
			(in thousands)
	Shares issued as of January 1		666,468			660,888			655,251
	Restricted stock issuances (net of forfeitures)(a)		(599	)		5,038			4,961
	Stock option exercises		323			542			565
	Preferred stock conversion		—			—			111
	Shares issued as of December 31		666,192			666,468			660,888
	___________________________________________
	(a)	In 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
	Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2013:
	Preferred Stock Series		Issue Date		Liquidation				Holder's Conversion Right		Conversion Rate		Conversion Price		Company's	Company's Market Conversion Trigger(a)
					Preference										Conversion
					per Share										Right From
	5.75% cumulative		May and		$	1,000			Any time		37.185		$	26.8926	May 17, 2015	$	34.9604
	convertible		Jun-10
	non-voting
	5.75% (series A)		May		$	1,000			Any time		35.9339		$	27.8289	May 17, 2015	$	36.1776
	cumulative		2010
	convertible
	non-voting
	4.50% cumulative convertible		Sep-05		$	100			Any time		2.2969		$	43.5375	September 15, 2010	$	56.5988
	5.00% cumulative convertible (series 2005B)		Nov-05		$	100			Any time		2.599		$	38.4757	November 15, 2010	$	50.0184
	___________________________________________
	(a)	Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the conversion date indicated if there are less than 250,000 shares of 4.50% or 5.00% (series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (series A) preferred stock outstanding.
	The following reflects the shares outstanding of our preferred stock for 2013, 2012 and 2011:
			5.75%			5.75% (A)			4.50%			5.00%
												(2005B)
			(in thousands)
	Shares outstanding as of January 1, 2013 and December 31, 2013		1,497			1,100			2,559			2,096
	Shares outstanding as of January 1, 2012 and December 31, 2012		1,497			1,100			2,559			2,096
	Shares outstanding as of January 1, 2011		1,500			1,100			2,559			2,096
	Conversion of preferred shares into common stock		(3	)		—			—			—
	Shares outstanding at December 31, 2011		1,497			1,100			2,559			2,096
	In 2011, 3,000 shares of our 5.75% Cumulative Convertible Preferred Stock were converted into 111,111 shares of our common stock. There was no gain or loss associated with this conversion.
	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 year ended December 31, 2013, 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, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		20				4				24
	Net current period other comprehensive income		22				(2		)		20
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	For the year ended December 31, 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statement of operations are detailed below.
	Details About Accumulated		Affected Line Item		Year Ended
	Other Comprehensive		in the Statement		31-Dec-13
	Income (Loss) Components		Where Net Income is Presented
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	20
	Investments:
	Impairment of investment		Impairment of investment		6
Sale of investment		Gain on sale of investment		(2		)
Total reclassifications for the period, net of tax				$	24
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 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 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 and $57 million as of December 31, 2013 and 2012, respectively, were reflected as restricted cash on our 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 December 31, 2013 and 2012, the redemption price and the liquidation preference were each approximately $1,245 and $1,305, respectively, per preferred share.
We have 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. 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 75 and 85 qualified net wells were added in 2013 and 2012, respectively. Through December 31, 2013, we had met the 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 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. 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 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 84 net wells in 2013 and 77 net wells in 2012. While 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. Through December 31, 2013, we were on target to meet the ORRI conveyance commitments associated with the CHK C-T transaction.
As of December 31, 2013 and 2012, $1.015 billion of noncontrolling interests on our consolidated balance sheets was attributable to CHK C-T. For 2013 and 2012, income of $75 million and $57 million, respectively, 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 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 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 amounts reserved for paying such dividends, approximately $37 million and $44 million as of December 31, 2013 and 2012, respectively, were reflected as restricted cash on our 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. As of December 31, 2012, $155 million of proceeds received from such divestitures was recorded as restricted cash in other long-term assets on our consolidated balance sheet. In 2013, we used all of the proceeds for CHK Utica capital expenditures.
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 December 31, 2013 and 2012, the redemption price and the liquidation preference were each approximately $1,252 and $1,322, 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 12 for further discussion of the joint venture. Under the development agreement, approximately 111 and 61 qualified net wells were added in 2013 and 2012, respectively. Through December 31, 2013, we had met the 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 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 149 new net wells in 2013 and 28 net wells in 2012. 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 December 31, 2013, we were on target to meet the ORRI conveyance commitments associated with the CHK Utica transaction.
As of December 31, 2013 and 2012, $807 million and $950 million of noncontrolling interests on our consolidated balance sheets, respectively, were attributable to CHK Utica. For 2013 and 2012, income of approximately $79 million and $88 million, respectively, was attributable to the noncontrolling interests of CHK Utica. In 2013, we purchased approximately 190,000 preferred shares of CHK Utica from existing investors for approximately $212 million, or approximately $1,115 per share plus accrued dividends, reducing the amount of outstanding preferred shares held by third-party investors by approximately 15%. The difference between the cash paid for the preferred shares and the carrying value of the noncontrolling interest acquired of $69 million is reflected in retained earnings and as a reduction to net income available to common stockholders for purposes of our EPS computations.
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 December 31, 2013 and 2012, we had drilled or caused to be drilled approximately 82 and 55 development wells, respectively, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $79 million and $140 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. As detailed in the table below, the distribution made with respect to the subordinated units to Chesapeake were either reduced or eliminated for each of the most recent six 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 years ended December 31, 2013 and 2012, the Trust declared and paid the following distributions:
Production Period		Distribution Date		Cash Distribution				Cash Distribution
				per				per
				Common Unit				Subordinated Unit
June 2013 - August 2013		November 29, 2013		$	0.6671			$	—
March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
June 2012 - August 2012		November 29, 2012		$	0.63			$	0.2208
March 2012 - May 2012		August 30, 2012		$	0.61			$	0.4819
December 2011 - February 2012		May 31, 2012		$	0.6588			$	0.6588
September 2011 - November 2011		March 1, 2012		$	0.7277			$	0.7277
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 consolidated financial statements. As of December 31, 2013 and 2012, $314 million and $356 million, respectively, of noncontrolling interests on our consolidated balance sheets, respectively, were attributable to the Trust. For 2013 and 2012, income of approximately $20 million and $35 million, respectively, was attributable to the Trust’s noncontrolling interests in our consolidated statements of operations. See Note 14 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 December 31, 2013 and 2012, $9 million and $5 million, respectively, of noncontrolling interests on our consolidated balance sheets, respectively, were attributable to Wireless. In each of 2013 and 2012, losses of $4 million were attributable to noncontrolling interests of Wireless in our consolidated statements of operations.

ShareBased_Compensation_Note

Share-Based Compensation (Note)	12 Months Ended
	Dec. 31, 2013
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.
	Share-Based Compensation Plans
	Under Chesapeake's Long Term Incentive Plan, restricted stock, stock options, stock appreciation rights, performance shares, performance share units and other stock awards may be awarded to employees, directors and consultants of Chesapeake. Subject to any adjustments as provided by the plan, the aggregate number of shares of common stock available for awards under the plan may not exceed 59,300,000 shares. The maximum period for exercise of an option or stock appreciation right may not be more than ten years from the date of grant, and the exercise price may not be less than the fair market value of the shares underlying the option or stock appreciation right on the date of grant. Awards granted under the plan become vested at specified dates or upon the satisfaction of certain performance or other criteria determined by a committee of the Board of Directors. No awards may be granted under the plan after September 30, 2014. The plan has been approved by our shareholders. There were 147,108, 170,151 and 68,824 shares of restricted stock issued to our non-employee directors under the plan in 2013, 2012 and 2011, respectively. Additionally, there were 2.5 million, 5.0 million and 4.5 million restricted stock issued, net of forfeitures, to employees and consultants during 2013, 2012 and 2011, respectively, under the plan. As of December 31, 2013, there were 12.7 million shares remaining available for issuance under the plan.
	Chesapeake's 2003 Stock Incentive Plan terminated in April 2013. Restricted stock was awarded to employees and consultants of Chesapeake under the plan prior to its termination. Subject to any adjustments as provided by the plan, the aggregate number of shares available for awards under the plan was limited to 10,000,000 shares. Restricted stock became vested at dates determined by a committee of the Board of Directors. The plan was approved by our shareholders. There were nominal amounts of restricted stock, net of forfeitures, issued under the plan during 2013 and 2012 and 0.4 million restricted stock, net of forfeitures, issued under the plan during 2011.
	Under Chesapeake's 2003 Stock Award Plan for Non-Employee Directors, a maximum of 10,000 shares of Chesapeake's common stock are awarded to each newly appointed non-employee director on his or her first day of service. Subject to any adjustments as provided by the plan, the aggregate number of shares which may be issued may not exceed 250,000 shares. This plan has been approved by our shareholders. In 2013, 2012 and 2011, 20,000, 30,000 and 10,000 shares, respectively, of common stock were awarded to new directors under the plan. As of December 31, 2013, there were 130,000 shares remaining available for issuance under the plan.
	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 2013, 2012 and 2011 is presented below.
			Number of		Weighted Average
			Unvested		Grant Date
			Restricted Shares		Fair Value
			(in thousands)
	Unvested shares as of January 1, 2013		18,899		$	23.72
	Granted		9,189		$	19.68
	Vested		(12,897	)	$	21.32
	Forfeited		(1,791	)	$	22.86
	Unvested shares as of December 31, 2013		13,400		$	23.38
	Unvested shares as of January 1, 2012		19,544		$	26.97
	Granted		9,480		$	21.13
	Vested		(8,620	)	$	28.08
	Forfeited		(1,505	)	$	24.57
	Unvested shares as of December 31, 2012		18,899		$	23.72
	Unvested shares as of January 1, 2011		21,375		$	28.68
	Granted		9,541		$	28.38
	Vested		(10,401	)	$	31.76
	Forfeited		(971	)	$	27.28
	Unvested shares as of December 31, 2011		19,544		$	26.97
	The aggregate intrinsic value of restricted stock that vested during 2013 was approximately $342 million based on the stock price at the time of vesting.
	As of December 31, 2013, there was $195 million of total unrecognized compensation cost related to unvested restricted stock. The cost is expected to be recognized over a weighted average period of approximately 3.6 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 2013, 2012 and 2011, we recognized reductions in tax benefits related to restricted stock of $14 million, $32 million and $23 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.
	Stock Options. In 2013, we granted members of our senior management team stock options that will vest ratably over a three-year period. We also granted retention awards to certain officers of stock options that will vest one-third on each of the third, fourth and fifth anniversaries of the grant date. Each stock option award has an exercise price equal to the closing price of the Company’s common stock on the grant date. Prior to 2006, we had granted stock options under several stock compensation plans which vested over a four-year period. Outstanding options expire ten years from the date of grant.
	We utilized the Black-Scholes option pricing model to measure the fair value of the stock options that were granted in 2013. The expected life of an option is determined using the "simplified method", as there is not adequate historical exercise behavior available. Volatility assumptions are estimated based on an average of historical volatility over the expected life of an option. The risk-free interest rate is based on the U.S. Treasury rate in effect at the time of the grant over the expected life of the option. The dividend yield is based on an annual dividend yield, taking into account the Company's current dividend policy over the expected life of the option. The Company used the following weighted-average assumptions to estimate the fair value of the stock options granted in 2013:
	Expected option life - years		6.49
	Volatility		48.47	%
	Risk-free interest rate		1.3	%
	Dividend yield		1.82	%
	The following table provides information related to stock option activity for 2013, 2012 and 2011:
			Number of		Weighted			Weighted		Aggregate
			Shares		Average			Average		Intrinsic
			Underlying		Exercise			Contract		Value(a)
			Options		Price			Life in
					Per Share			Years
			(in thousands)							($ in millions)
	Outstanding at January 1, 2013		481		$	12.69		0.96		$	2
	Granted		5,264		$	19.32
	Exercised		(346	)	$	10.82				$	11
	Expired		(131	)	$	19.31
	Outstanding at December 31, 2013		5,268		$	19.28		6.66		$	41
	Exercisable at December 31, 2013		1,552		$	18.82		1.97		$	13
	Outstanding at January 1, 2012		1,051		$	9.84		1.41		$	13
	Exercised		(570	)	$	7.45				$	7
	Outstanding and exercisable at December 31, 2012		481		$	12.69		0.96		$	2
	Outstanding at January 1, 2011		1,808		$	8.9		2.03		$	31
	Exercised		(757	)	$	7.59				$	15
	Outstanding and exercisable at December 31, 2011		1,051		$	9.84		1.41		$	13
	___________________________________________
	(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 December 31, 2013, there was $16 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately 2.5 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 years ended December 31, 2013 and 2012, we recognized excess tax benefits related to stock options of $1 million and $2 million, respectively. During the year ended December 31, 2011, we recognized a reduction in tax benefits related to stock options of $3 million. All amounts were recorded as adjustments to additional paid-in capital and deferred income taxes.
	We recorded the following compensation related to restricted stock and stock options during the years ended December 31, 2013, 2012 and 2011:
			Years Ended December 31,
			2013			2012			2011
			($ in millions)
Natural gas and oil properties		$	52		$	71		$	112
General and administrative expenses		60			71			92
Natural gas, oil and NGL production expenses		21			24			33
Marketing, gathering and compression expenses		7			15			17
Oilfield services expenses		10			10			11
Total		$	150		$	191		$	265
Liability-Classified Awards
Performance Share Units. In 2012 and 2013, we granted PSUs to senior management under our Long Term Incentive Plan which settle in cash at the end of their respective performance periods and which 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 awards are settled in cash on the third anniversary of the awards. The ultimate number of units earned is based on the achievement of relative and absolute total shareholder return (TSR) and production and proved reserve growth performance goals. The market condition is a function of TSR, 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% in all cases and at 100% in situations where the Company’s absolute TSR is less than zero. The following table presents a summary of our PSU awards as of December 31, 2013:
		Units		Fair Value			Fair Value				Liability for
				as of							Vested
				Grant Date							Amount
				($ in millions)
2012 Awards (a)
Payable 2014		278,083		$	8		$	11			$	11
Payable 2015		834,248		23			31				30
Total 2012 Awards		1,112,331		$	31		$	42			$	41
2013 Awards
Payable 2016		1,600,438		$	35		$	58			$	49
___________________________________________
(a)	In 2013, we paid $2 million related to 2012 PSU awards.
We recorded the following compensation related to PSUs during the years ended December 31, 2013, 2012 and 2011:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
Natural gas and oil properties		$	9		$	4		$	—
General and administrative expenses		34			8			—
Natural gas, oil and NGL production expenses		2			1			—
Marketing, gathering and compression expenses		2			1			—
Oilfield services expenses		1			—			—
Total		$	48		$	14		$	—

Employee_Benefit_Plans_Note

Employee Benefit Plans (Note)	12 Months Ended
	Dec. 31, 2013
Compensation and Retirement Disclosure [Abstract]	'
Compensation and Employee Benefit Plans [Text Block]	'
	Employee Benefit Plans
	Our qualified 401(k) profit sharing plan (401(k) Plan) is the Chesapeake Energy Corporation Savings and Incentive Stock Bonus Plan, which is open to employees of Chesapeake and all our subsidiaries except certain employees of Chesapeake Appalachia, L.L.C. Eligible employees may elect to defer compensation through voluntary contributions to their 401(k) Plan accounts, subject to plan limits and those set by the IRS. Chesapeake matches employee contributions dollar for dollar (subject to a maximum contribution of 15% of an employee's base salary and performance bonus) with Chesapeake common stock purchased in the open market. The Company contributed $81 million, $91 million and $72 million to the 401(k) Plan in 2013, 2012 and 2011, respectively.
	Chesapeake also maintains a nonqualified deferred compensation plan, the Chesapeake Energy Corporation Amended and Restated Deferred Compensation Plan (DC Plan). To be eligible to participate in the DC Plan, an active employee must have a base salary of at least $150,000, have an employment agreement with Chesapeake, have a hire date on or before the first business day in October immediately preceding the year in which the employee is able to participate, or be designated as eligible to participate. Additionally, the employee has to have made the maximum contribution allowable under the 401(k) Plan. Chesapeake matches 100% of employee contributions up to 15% of base salary and performance bonus in the aggregate for the DC Plan with Chesapeake common stock, and an employee who is at least age 55 may elect for the matching contributions to be made in any one of the investment options. The maximum compensation that can be deferred by employees under all Company deferred compensation plans, including the Chesapeake 401(k) Plan, is a total of 75% of base salary and 100% of performance bonus. We contributed $14 million, $16 million and $12 million to the DC Plan during 2013, 2012 and 2011, respectively, to fund the match. In addition, in 2012 the Board of Directors adopted a Deferred Compensation Plan for Non-Employee Directors (Director DC Plan). The Company's non-employee directors are able to defer up to 100% of director cash compensation into the Director DC Plan and invest in Chesapeake common stock, but the plan does not provide for Company matching contributions.
	Any assets placed in trust by Chesapeake to fund future obligations of the Company's nonqualified deferred compensation plans are subject to the claims of creditors in the event of insolvency or bankruptcy, and participants are general creditors of the Company as to their deferred compensation in the plans.
	Chesapeake maintains no post-employment benefit plans except those sponsored by its wholly owned subsidiary, Chesapeake Appalachia, L.L.C. Participation in these plans is limited to existing employees who are union members and former employees who were union members. The Chesapeake Appalachia, L.L.C. benefit plans provide health care and life insurance benefits to eligible employees upon retirement. We account for these benefits on an accrual basis. As of December 31, 2013, the Company had accrued approximately $3 million in accumulated post-employment benefit liability.

Derivative_and_Hedging_Activit

Derivative and Hedging Activities (Note)	12 Months Ended
	Dec. 31, 2013
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 December 31, 2013 and 2012, 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 natural gas basis protection swaps typically 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 oil basis protection swaps typically 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 December 31, 2013 and 2012 are provided below.
			31-Dec-13							31-Dec-12
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		448			$	(23	)		49			$	24
	Three-way collars		288			(7		)		—			—
	Call options		193			(210		)		193			(240		)
	Call swaptions		12			—				—			—
	Basis protection swaps		68			3				111			(15		)
	Total natural gas		1,009			(237		)		353			(231		)
	Oil (mmbbl):
	Fixed-price swaps		25.3			(50		)		28.1			68
	Call options		42.5			(265		)		73.8			(748		)
	Call swaptions		—			—				5.3			(13		)
	Basis protection swaps		0.4			1				5.5			—
	Total oil		68.2			(314		)		112.7			(693		)
	Total estimated fair value					$	(551	)					$	(924	)
	The components of natural gas, oil and NGL sales for the years ended December 31, 2013, 2012 and 2011 are presented below.
			Years Ended December 31,
			2013				2012				2011
			($ in millions)
	Natural gas, oil and NGL sales		$	6,923			$	5,359			$	5,259
	Gains on natural gas, oil and NGL derivatives		129				919				772
	Losses on ineffectiveness of cash flow hedges		—				—				(7		)
	Total natural gas, oil and NGL sales		$	7,052			$	6,278			$	6,024
	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 Cash Flow Hedges.
	Interest Rate Derivatives
	As of December 31, 2013 and 2012, 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 and the estimated fair value of our interest rate derivative liabilities as of December 31, 2013 and 2012 are provided below.
			31-Dec-13								31-Dec-12
			Notional				Fair				Notional				Fair
			Amount				Value				Amount				Value
							($ in millions)
	Interest rate swaps		$	2,250			$	(98	)		$	1,050			$	(35	)
	The components of interest expense for the years ended 2013, 2012 and 2011 are presented below.
			Years Ended December 31,
			2013				2012				2011
			($ in millions)
	Interest expense on senior notes		$	740			$	732			$	653
	Interest expense on credit facilities		38				70				70
	Interest expense on term loans		116				173				—
	(Gains) losses on interest rate derivatives		58				(7		)		14
	Amortization of loan discount, issuance costs and other		91				89				39
	Capitalized interest		(816		)		(980		)		(732		)
	Total interest expense		$	227			$	77			$	44
	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 $14 million in net gains in earnings related to such transactions.
	Foreign Currency Derivatives
	In December 2006, we issued €600 million of 6.25% Euro-denominated Senior Notes due 2017. Concurrent with the issuance of the euro-denominated senior notes, we entered into cross currency swaps to mitigate our exposure to fluctuations in the euro relative to the dollar over the term of the notes. In May 2011, we purchased and subsequently retired €256 million in aggregate principal amount of these senior notes following a tender offer, and we simultaneously unwound the cross currency swaps for the same principal amount. Under the terms of the remaining cross currency swaps, 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 terms of the cross currency swaps were based on the dollar/euro exchange rate on the issuance date of $1.3325 to €1.00. Through the cross currency swaps, we have eliminated any potential variability in our expected cash flows related to changes in foreign exchange rates and therefore the swaps are designated as cash flow hedges. The fair values of the cross currency swaps are recorded on the consolidated balance sheet as an asset of $2 million as of December 31, 2013. The euro-denominated debt in long-term debt has been adjusted to $473 million as of December 31, 2013 using an exchange rate of $1.3743 to €1.00.
	Additional Disclosures Regarding Derivative Instruments and Hedging Activities
	The following table presents the fair value and location of each classification of derivative instrument disclosed in the consolidated balance sheets as of December 31, 2013 and 2012 on a gross basis without regard to same-counterparty netting:
					Fair Value
					December 31,
			Balance Sheet Location		2013				2012
				($ in millions)
Asset Derivatives:
Designated as hedging instruments:
Foreign currency contracts		Long-term derivative instruments		$	2			$	—
Total				2				—
Not designated as hedging instruments:
Commodity contracts		Short-term derivative instruments		29				110
Commodity contracts		Long-term derivative instruments		11				5
Total				40				115
Liability Derivatives:
Designated as hedging instruments:
Foreign currency contracts		Long-term derivative instruments		—				(20		)
Total				—				(20		)
Not designated as hedging instruments:
Commodity contracts		Short-term derivative instruments		(231		)		(157		)
Commodity contracts		Long-term derivative instruments		(362		)		(882		)
Interest rate contracts		Short-term derivative instruments		(6		)		—
Interest rate contracts		Long-term derivative instruments		(92		)		(35		)
Total				(691		)		(1,074		)
Total derivative instruments				$	(649	)		$	(979	)
As of December 31, 2013 and 2012, we did not have any cash collateral balances for these derivatives.
The following tables present the netting offsets of derivative assets and liabilities in the consolidated balance sheets as of December 31, 2013 and December 31, 2012:
		31-Dec-13
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
Commodity Contracts:
Gross amounts of recognized assets (liabilities)		$	29			$	11			$	(231	)		$	(362	)
Gross amounts offset in the consolidated balance sheet		(29		)		(9		)		29				9
Net amounts of assets (liabilities) presented in the consolidated balance sheet		—				2				(202		)		(353		)
Interest Rate Contracts:
Gross amounts of recognized assets (liabilities)		—				—				(6		)		(92		)
Gross amounts offset in the consolidated balance sheet		—				—				—				—
Net amounts of assets (liabilities) presented in the consolidated balance sheet		—				—				(6		)		(92		)
Foreign Currency Contracts:
Gross amounts of recognized assets (liabilities)		—				2				—				—
Gross amounts offset in the consolidated balance sheet		—				—				—				—
Net amounts of assets (liabilities) presented in the consolidated balance sheet		—				2				—				—
Total derivatives as reported		$	—			$	4			$	(208	)		$	(445	)
		31-Dec-12
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
Commodity Contracts:
Gross amounts of recognized assets (liabilities)		$	110			$	5			$	(157	)		$	(882	)
Gross amounts offset in the consolidated balance sheet		(52		)		(3		)		52				3
Net amounts of assets (liabilities) presented in the consolidated balance sheet		58				2				(105		)		(879		)
Interest Rate Contracts:
Gross amounts of recognized assets (liabilities)		—				—				—				(35		)
Gross amounts offset in the consolidated balance sheet		—				—				—				—
Net amounts of assets (liabilities) presented in the consolidated balance sheet		—				—				—				(35		)
Foreign Currency Contracts:
Gross amounts of recognized assets (liabilities)		—				—				—				(20		)
Gross amounts offset in the consolidated balance sheet		—				—				—				—
Net amounts of assets (liabilities) presented in the consolidated balance sheet		—				—				—				(20		)
Total derivatives as reported		$	58			$	2			$	(105	)		$	(934	)
A consolidated summary of the effect of derivative instruments on our consolidated statements of operations for the years ended December 31, 2013, 2012 and 2011 is provided below, separating fair value, cash flow and undesignated derivatives.
Fair Value Hedges. The following table presents the gain (loss) recognized in our consolidated statements of operations for terminated instruments that were designated as fair value derivatives:
				Years Ended December 31,
Fair Value Derivatives		Location of Gain (Loss)		2013				2012				2011
				($ in millions)
Interest rate contracts		Interest expense		$	5			$	8			$	16
Cash Flow Hedges. A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Years Ended December 31,
		2013								2012							2011
		Before				After				Before				After			Before			After
		Tax				Tax				Tax				Tax			Tax			Tax
		($ in millions)
Balance, beginning of period		$	(304	)		$	(189	)		$	(287	)		$	(178	)	$	(291	)	$	(181	)
Net change in fair value		3				2				10				6			368			228
(Gains) losses reclassified to income		32				20				(27		)		(17		)	(364		)	(225		)
Balance, end of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
Approximately $159 million of the $167 million of accumulated other comprehensive loss as of December 31, 2013 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 December 31, 2013, we expect to transfer approximately $23 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amounts will be transferred by December 31, 2022. As of December 31, 2013, none of our open commodity derivative instruments were designated as cash flow hedges.
The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) related to instruments designated as cash flow derivatives:
				Years Ended December 31,
Cash Flow Derivatives		Location of Gain (Loss)		2013				2012				2011
				($ in millions)
Gain (Loss) Recognized in AOCI (Effective Portion):
Commodity contracts		AOCI		$	—			$	—			$	392
Foreign currency contracts		AOCI		3				10				(24		)
				$	3			$	10			$	368
Gain (Loss) Reclassified from AOCI (Effective Portion):
Commodity contracts		Natural gas, oil and NGL sales		$	(32	)		$	27			$	402
Foreign currency contracts		Interest expense		—				—				(18		)
Foreign currency contacts		Loss on purchase of debt		—				—				(20		)
				$	(32	)		$	27			$	364
Gain (Loss) Recognized in Income:
Ineffective portion		Natural gas, oil and NGL sales		$	—			$	—			$	(7	)
Amount initially excluded from effectiveness testing		Natural gas, oil and NGL sales		—				—				22
				$	—			$	—			$	15
Undesignated Derivatives. The following table presents the gain (loss) recognized in our consolidated statements of operations for instruments not designated as either cash flow or fair value hedges:
				Years Ended December 31,
Derivative Contracts		Location of Gain (Loss)		2013				2012				2011
				($ in millions)
Commodity contracts		Natural gas, oil and NGL		$	159			$	892			$	348
Interest rate contracts		Interest expense		(63		)		(1		)		(12		)
Total				$	96			$	891			$	336
Credit Risk
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 December 31, 2013, our natural gas, oil and interest rate derivative instruments were spread among 16 counterparties.
Hedging Facility
We have a multi-counterparty secured hedging facility with 16 counterparties that have committed to provide 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 under the terms of the facility. As of December 31, 2013, we had hedged under the facility 221 mmboe of our future production with price derivatives and 12 mmboe with basis derivatives. The multi-counterparty facility allows us to enter into cash-settled natural gas, oil and NGL price and basis derivatives with the counterparties. Our obligations under the multi-counterparty facility are 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. 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. The maximum volume-based trading capacity under the facility is governed by the expected production of the pledged reserve collateral, and volume-based trading limits are applied separately to price and basis derivatives. In addition, there are volume-based sub-limits for natural gas, oil and NGL derivative instruments. 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 facility does not have a maturity date. Counterparties to the agreement have the right to cease entering into derivative instruments with the Company on a prospective basis as long as obligations associated with any existing transactions in the facility continue to be satisfied in accordance with the terms of the agreement.

Natural_Gas_and_Oil_Property_D

Natural Gas and Oil Property Divestitures (Note)	12 Months Ended
	Dec. 31, 2013
Business Combinations [Abstract]	'
Mergers, Acquisitions and Dispositions Disclosure [Text Block]	'
	Natural Gas and Oil Property Divestitures
	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. Below is a discussion of our major oil and gas property divestitures for the years ended December 31, 2013, 2012 and 2011.
	In 2013, we sold a wholly owned subsidiary, MKR Holdings, L.L.C. (MKR), to Chief Oil and Gas and two of its working interest partners, Enerplus and Tug Hill. Net proceeds from the transaction were approximately $490 million. MKR held producing wells and undeveloped acreage in the Marcellus Shale in Bradford, Lycoming, Sullivan, Susquehanna and Wyoming counties, Pennsylvania.
	In 2013, we sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. Subsequent to closing, we received approximately $47 million of additional net proceeds for post-closing adjustments. The assets sold included our operated and non-operated interests in approximately 9,600 net acres in DeSoto and Caddo parishes, Louisiana.
	In 2013, we sold assets in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. Subsequent to closing, in 2013 we received approximately $32 million of net proceeds for post-closing adjustments and may receive up to $64 million of additional net proceeds for further post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas.
	In 2012, we sold the vast majority of our Permian Basin assets, representing approximately 6% of our total proved reserves as of June 30, 2012, in three separate transactions for total net cash proceeds of approximately $3.091 billion. Approximately $466 million of additional consideration was withheld subject to certain title, environmental and other standard contingencies. Following the closing, we received approximately $355 million of such consideration, including $320 million received subsequent to December 31, 2012, and we expect to receive the majority of the remaining contingent amount in 2014. Of the total proceeds, we allocated approximately $42 million to our Permian Basin midstream and other fixed assets. The remaining proceeds were allocated to our Permian Basin natural gas and oil properties.
	In 2012, we sold approximately 40,000 net acres of noncore leasehold in the Chitwood Knox play in Oklahoma for approximately $540 million in cash.
	In 2012, we sold producing assets in the Midland Basin portion of the Permian Basin to affiliates of EnerVest, Ltd. for approximately $376 million in cash.
	In 2012, we sold approximately 72,000 net acres of noncore leasehold in the Utica Shale play in Ohio to affiliates of EnerVest, Ltd. for approximately $358 million in cash.
	In 2012, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for net proceeds of approximately $572 million.
	In 2011, we sold all of our Fayetteville Shale assets in central Arkansas to BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (NYSE:BHP; ASX:BHP), for net proceeds of approximately $4.65 billion in cash. The properties sold consisted of approximately 487,000 net acres of leasehold, net production at closing of approximately 415 mmcfe per day and midstream assets consisting of approximately 420 miles of pipeline. Of the total proceeds received, $350 million was allocated to our Fayetteville Shale midstream assets and a $7 million gain was recorded on the divestiture of those assets. The remainder of the proceeds was allocated to our Fayetteville Shale natural gas and oil properties.
	Joint Ventures
	In 2013, we completed a strategic joint venture with Sinopec International Petroleum Exploration and Production Corporation (Sinopec) in which Sinopec purchased a 50% undivided interest in approximately 850,000 acres (425,000 acres net to Sinopec) in the Mississippi Lime play in northern Oklahoma. Total consideration for the transaction was approximately $1.020 billion in cash, of which approximately $949 million of net proceeds was received upon closing. We also received an additional $90 million at closing related to closing adjustments for activity between the effective date and closing date of the transaction. We may receive up to an additional $71 million of net proceeds pursuant to post-closing adjustments. All exploration and development costs in the joint venture are shared proportionately between the parties with no drilling carries involved.
	As of December 31, 2013, 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			596
	Niobrara		CNOOC	Feb-11		33.30%		570				697		(f)	1,267			135
	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		$	731
	____________________________________________
	(a)	Joint venture partners include 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 December 31, 2013.
	(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 carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.
	(f)	The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration.
	During 2013, 2012 and 2011, our drilling and completion costs included the benefit of approximately $884 million, $784 million and $2.570 billion, respectively, in drilling and completion carries paid by our joint venture partners.
	During 2013, 2012 and 2011, 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 $58 million, $272 million and $511 million, respectively.
	Volumetric Production Payments
	From time to time, we have sold certain of our producing assets which are 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 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 Texas		180				44			0.3		—		46
				Gulf Coast
	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 during 2013, 2012 and 2011 were as follows:
			Year Ended December 31, 2013
	VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		13.5		547			1,509.00			25.8
9		17		213.2			455.7			21
8		68.1		—			—			68.1
6		4.8		24			—			4.9
5		7.5		25.4			—			7.7
4		10.2		54.7			—			10.5
3		8.1		—			—			8.1
2		10.3		—			—			10.3
1		14.5		—			—			14.5
		154		864.3			1,964.70			170.9
		Year Ended December 31, 2012
VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		18.1		727			1,729.10			32.8
9		18.4		249.3			643.6			23.7
8		79.7		—			—			79.7
7		0.4		490.3			—			3.4
6		5.3		24			—			5.5
5		8.8		27.4			—			9
4		11.7		62.8			—			12.2
3		9.3		—			—			9.3
2		11.4		—			—			11.3
1		15.3		—			—			15.3
		178.4		1,580.80			2,372.70			202.2
		Year Ended December 31, 2011
VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		—		—			—			—
9		17.3		250.5			615.4			22.5
8		101.2		—			—			101.2
7		0.4		773			—			5
6		6		27			—			6.2
5		11		35.9			—			11.2
4		13.8		75.1			—			14.3
3		10.7		—			—			10.7
2		12.5		—			—			12.5
1		16.3		—			—			16.3
		189.2		1,161.50			615.4			199.9
The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2013 were as follows:
			Volume Remaining as of December 31, 2013
VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
		(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
10		98	48.6			1.7			6			94.8
9		86	88.7			1			2.3			108.9
8		20	96.5			—			—			96.5
6		73	21.4			0.2			—			22.3
5		37	16.9			0.1			—			17.2
4		36	24.3			0.1			—			25.1
3		67	31.1			—			—			31.1
2		64	20			—			—			20
1		108	105.4			—			—			105.4
			452.9			3.1			8.3			521.3
In September 2012, to facilitate the sales process associated with our Permian Basin divestiture packages, we purchased the remaining reserves from our Permian Basin VPP (VPP #7), originally sold in June 2010, for $313 million. The reserves purchased totaled 28 bcfe and were subsequently sold to the buyers of our Permian Basin assets.

Investments_Note

Investments (Note)	12 Months Ended
	Dec. 31, 2013
Investments [Abstract]	'
Investments Disclosure [Text Block]	'
	Investments
	A summary of our investments, including our approximate ownership percentage as of December 31, 2013 and 2012, is presented below.
				Approximate			Carrying
				Ownership %			Value
		Accounting		December 31,			December 31,
		Method		2013	2012		2013				2012
							($ in millions)
	FTS International, Inc.	Equity		30%	30%		$	138			$	298
	Chaparral Energy, Inc.	Equity		20%	20%		143				141
	Sundrop Fuels, Inc.	Equity		56%	50%		135				111
	Clean Energy Fuels Corp.	Fair Value		—%	1%		—				12
	(common stock)
	Clean Energy Fuels Corp.	Cost		—%	—%		—				100
	(convertible notes)
	Gastar Exploration Ltd.	Fair Value		—%	10%		—				8
	Other	—		—%	—%		61				58
	Total investments						$	477			$	728
	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. In 2013, we recorded negative equity method and other adjustments, prior to intercompany profit eliminations, of $177 million for our share of FTS’s net loss and recorded an accretion adjustment of $14 million related to the excess of our underlying equity in net assets of FTS over our carrying value. The loss in 2013 primarily represents our proportionate share, net of tax, of an impairment recorded by FTS related to its non-depreciable assets. Additionally, in 2013, we purchased FTS common stock offered to existing stockholders for $3 million.
	The carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $54 million as of December 31, 2013, of which $14 million was attributed to non-depreciable assets. During 2013, the value attributed to non-depreciable assets decreased by $282 million, which primarily represents our proportionate share, net of tax, of an impairment recorded by FTS related to its non-depreciable assets noted above. The value not attributed to non-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 2013, we recorded positive equity method adjustments of $10 million related to our share of Chaparral’s net income, a $5 million charge related to our share of its other comprehensive income, and an amortization adjustment of $3 million related to our carrying value in excess of our underlying equity in net assets. The carrying value of our investment in Chaparral was in excess of our underlying equity in net assets by approximately $48 million as of December 31, 2013. This excess was attributed to the natural gas and oil reserves held by Chaparral and was being amortized over the estimated life of these reserves based on a unit of production rate. Subsequent to December 31, 2013, we sold our investment in Chaparral for cash proceeds of $215 million.
	Sundrop Fuels, Inc. Sundrop Fuels, Inc. (Sundrop), is a privately held cellulosic biofuels company based in Longmont, Colorado that is constructing a nonfood biomass-based “green gasoline” plant. In 2013, we recorded a $16 million charge related to our share of Sundrop’s net loss. Additionally, in 2013, we funded our final investment of $40 million upon Sundrop’s achievement of certain operational milestones. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $62 million as of December 31, 2013. This excess will be amortized over the life of the plant, once it is placed into service.
	Sold Investments
	Clean Energy Fuels Corp. In 2013, we sold all of our shares of Clean Energy Fuels Corp. (NASDAQ:CLNE) (Clean Energy) common stock for cash proceeds of approximately $13 million. We recorded a $3 million gain related to the sale. In 2013, we sold our $100 million investment in Clean Energy convertible notes for cash proceeds of $85 million. The buyer also assumed our commitment to purchase the third and final $50 million tranche of Clean Energy convertible notes. We recorded a $15 million loss related to this sale.
	Gastar Exploration Ltd. In 2013, we sold our investment in Gastar Exploration Ltd. (NYSE MKT:GST) for cash proceeds of $10 million.
	Chesapeake Midstream Partners, L.P. In 2012, we sold all of our common and subordinated units representing limited partner interests in Chesapeake Midstream Partners, L.P., now named Access Midstream Partners, L.P. (NYSE:ACMP), and all of our limited liability company interests in the sole member of its general partner to funds affiliated with Global Infrastructure Partners for cash proceeds of $2.0 billion. We recorded a $1.032 billion gain associated with the transaction, including the recognition of a $13 million deferred gain related to equipment previously sold to ACMP. During 2012, we recorded positive equity method adjustments of $46 million for our share of ACMP’s income, received cash distributions of $56 million from ACMP and recorded accretion adjustments of $4 million related to our share of equity in excess of cost.
	Glass Mountain Pipeline, LLC. In 2012, our wholly owned midstream subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), entered into an agreement with two other parties to form Glass Mountain Pipeline, LLC to construct a 210-mile pipeline in western and north central Oklahoma in which CMD had a 50% ownership interest. In 2012, CMD sold its interest for $99 million and recorded a gain of $62 million.
	Other. In 2013, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.
	The table below presents summarized financial information for our significant equity method investments, including FTS and Sundrop. The investee financial information reflects the most current financial information available to investors and includes lags in financial reporting of up to one quarter.
		Years Ended December 31,
		2013			2012				2011
		($ in millions)
	Current assets	$	521		$	892			$	732
	Noncurrent assets	$	1,859		$	4,225			$	5,175
	Current liabilities	$	192		$	207			$	277
	Noncurrent liabilities	$	1,468		$	1,726			$	1,916
	Gross revenue	$	1,807		$	2,190			$	2,209
	Operating expense	$	3,926		$	3,089			$	1,630
	Net income (loss)	$	(2,459	)	$	(968	)		$	494

Variable_Interest_Entities_Not

Variable Interest Entities (Note)	12 Months Ended
	Dec. 31, 2013
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 8. 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 December 31, 2013, approximately $320 million of net natural gas and oil properties, $22 million of other current liabilities, $1 million of cash and cash equivalents and $5 million of short-term derivative liabilities were attributable to the Trust. We have presented parenthetically on the face of the 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)	12 Months Ended
	Dec. 31, 2013
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]	'
Other Property and Equipment [Text Block]	'
	Other Property and Equipment
	Other Property and Equipment
	A summary of other property and equipment held for use and the useful lives thereof is as follows:
		December 31,						Useful
		2013			2012			Life
		($ in millions)						(in years)
	Oilfield services equipment	$	2,192		$	2,130		15-Mar
	Buildings and improvements	1,433			1,580			Oct-39
	Natural gas compressors	368			505			20-Mar
	Land	212			515			—
	Other	1,190			1,178			20-Feb
	Total other property and equipment, at cost	5,395			5,908
	Less: accumulated depreciation	(1,584		)	(1,293		)
	Total other property and equipment, net	$	3,811		$	4,615
	Net Gains on Sales of Fixed Assets
	A summary by asset class of (gains) or losses on sales of fixed assets for the years ended December 31, 2013, 2012 and 2011 is as follows:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Gathering systems and treating plants	$	(326	)	$	(286	)	$	(440	)
	Drilling rigs and equipment	2			10			1
	Buildings and land	27			7			2
	Other	(5		)	2			—
	Total net gains on sales of fixed assets	$	(302	)	$	(267	)	$	(437	)
	Gathering Systems and Treating Plants. In 2013, CMD sold its wholly owned midstream subsidiary, Mid-America Midstream Gas Services, L.L.C. (MAMGS), to SemGas, L.P. (SemGas), a wholly owned subsidiary of SemGroup Corporation, for net proceeds of approximately $306 million, subject to post-closing adjustments. We recorded a $141 million gain associated with this transaction. MAMGS owns certain gathering and processing assets located in the Mississippi Lime play, and the transaction with SemGas included a new long-term fixed-fee gathering and processing agreement covering acreage dedication areas in the Mississippi Lime play.
	In 2013, CMD sold its wholly owned subsidiary, Granite Wash Midstream Gas Services, L.L.C. (GWMGS), to MarkWest Oklahoma Gas Company, L.L.C., a wholly owned subsidiary of MarkWest Energy Partners, L.P. (NYSE:MWE), for net proceeds of approximately $252 million, subject to post-closing adjustments. We recorded a $105 million gain associated with this transaction. GWMGS owns certain midstream assets in the Anadarko Basin that service the Granite Wash and Hogshooter formations. The transaction with MWE included new long-term fixed-fee agreements for gas gathering, compression, treating and processing services.
	In 2013, 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.
	In 2012, CMD sold its wholly owned subsidiary, CMO, which held a majority of our midstream business, to ACMP for total consideration of $2.16 billion in cash. In connection with the sale, Chesapeake entered into new long-term agreements in which ACMP agreed to perform certain natural gas gathering and related services for us within specified acreage dedication areas in exchange for (i) cost-of-service based fees redetermined annually beginning January 2014 in the Niobrara and Marcellus shale plays, (ii) cost-of-service based fees redetermined annually beginning October 2013 for the wet gas gathering systems and January 2014 for the dry gas gathering systems in the Utica Shale play, (iii) tiered fees based on volumes delivered relative to scheduled volumes through 2015 and thereafter cost-of-service based fees redetermined annually in the Eagle Ford Shale play, and (iv) annual minimum volume commitments and a fixed fee per mmbtu of natural gas gathered, subject to an annual 2.5% rate escalation, through 2017 and thereafter tiered fees based on volumes delivered relative to scheduled volumes in the Haynesville Shale play. We recorded a $289 million gain associated with this transaction.
	In 2012, we sold our oil gathering business and related assets in the Eagle Ford Shale to Plains Pipeline, L.P. for cash proceeds of approximately $115 million. Subsequent to December 31, 2012, we received an additional $10 million of proceeds upon satisfaction of a certain closing contingency. We recorded a $3 million gain associated with this transaction. In connection with the sale, we entered into new gathering and transportation agreements covering acreage dedication areas.
	In 2011, CMD sold its wholly owned subsidiary, Appalachia Midstream Services, L.L.C. (AMS), which held substantially all of our Marcellus Shale midstream assets, to ACMP for total consideration of $884 million and recorded a gain of $439 million. We, and other producers in the area, have 15-year cost of service gathering and compression agreements with AMS that include acreage dedications and an annual fee redetermination.
	Buildings and Land. In 2013, we recorded net losses of $27 million on sales of buildings and land located primarily in our Barnett Shale operating area.
	Acquisition of Bronco Drilling
	In June 2011, we acquired Bronco Drilling Company, Inc., a publicly traded contract land drilling services company, for an aggregate purchase price of approximately $339 million, or $11.00 per share of Bronco common stock. The acquisition was accounted for as a business combination which, among other things, requires assets acquired and liabilities assumed to be measured at their acquisition date fair values.
	Assets and Liabilities Held for Sale
	In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of December 31, 2013 we were continuing to pursue the sale of various land and buildings located in the Fort Worth, Texas area. The land and buildings in both the Oklahoma City and Fort Worth areas are reported under our other segment. We are also pursuing the sale of various other property and equipment, including certain drilling rigs, compressors and gathering systems. The drilling rigs are reported under our oilfield services operating segment, and the compressors and gathering systems are reported under our marketing, gathering and compression operating segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets qualified as held for sale as of December 31, 2013. Natural gas and oil properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets and liabilities held for sale on our consolidated balance sheets as of December 31, 2013 and 2012 is detailed below.
		December 31,
		2013			2012
		($ in millions)
	Accounts receivable	$	—		$	4
	Current assets held for sale	$	—		$	4
	Natural gas gathering systems and treating plants, net of accumulated depreciation	$	11		$	352
	Oilfield services equipment, net of accumulated depreciation	29			27
	Compressors, net of accumulated depreciation	285			—
	Buildings and land, net of accumulated depreciation	405			255
	Property and equipment held for sale, net	$	730		$	634
	Accounts payable	$	—		$	4
	Accrued liabilities	—			17
	Current liabilities held for sale	$	—		$	21

Impairments_Note

Impairments (Note)	12 Months Ended
	Dec. 31, 2013
Asset Impairment Charges [Abstract]	'
Asset Impairment Charges [Text Block]	'
	Impairments
	Impairment of Natural Gas and Oil Properties
	We review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC. This quarterly review, referred to as a ceiling test, is described in Note 1 under Natural Gas and Oil Properties. In 2012, capitalized costs of natural gas and oil properties exceeded the ceiling, resulting in an impairment in the carrying value of natural gas and oil properties of $3.315 billion. Cash flow hedges as of September 30, 2012, which related to future periods, increased the ceiling test impairment by $279 million. We were not required to record impairments of natural gas and oil properties for any other quarter in 2012 or for any quarters in 2011 or 2013.
	Impairments of Fixed Assets and Other
	A summary of our impairments of fixed assets by asset class and other charges for the years ended December 31, 2013, 2012 and 2011 is as follows:
		Years Ended December 31,
		2013		2012		2011
		($ in millions)
	Buildings and land	$	366	$	248	$	3
	Drilling rigs and equipment	71		60		—
	Gathering systems	22		6		43
	Other	87		26		—
	Total impairments of fixed assets and other	$	546	$	340	$	46
	Buildings and Land. In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. Some of these assets have been 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 December 31, 2013. We recognized an impairment loss of $186 million during 2013 on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell. See Assets and Liabilities Held for Sale in Note 15. We measured the fair value of these assets based on prices from orderly sales transactions for comparable properties between market participants, discounted cash flows or purchase offers we received from third parties.
	Given the impairment losses associated with these assets, in 2013 we tested other noncore buildings and land that we own in the Oklahoma City area for recoverability. Our estimate of the future undiscounted cash flows for these assets was less than their carrying amounts, and we recognized an additional impairment loss of $69 million on these assets for the difference between the carrying amount and fair value of the assets. We measured the fair value of these assets based on prices from orderly sales transactions for comparable properties between market participants and, in certain cases, discounted cash flows.
	Due to a decrease in the estimated market prices of certain surface land classified as held for sale in the Fort Worth, Texas area, we recognized an additional impairment loss of $86 million in 2013. We measured the fair value of these assets based on recent prices from orderly sales transactions for comparable properties between market participants. In addition, we tested other noncore surface land that we own in the Fort Worth area for recoverability in 2013 and recognized an additional impairment loss of $10 million on these assets for the difference between the carrying amount and fair value of the assets. In 2012, we recognized $248 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. The change in business climate in the Barnett Shale in 2012, evidenced by our significant reduction in Barnett Shale operations and depressed natural gas prices, required us to test these long-lived assets for recoverability. We received a purchase offer from a third party that we used to determine the fair value of the office building and measured the fair value of the surface land using prices from orderly sales transactions for comparable properties between market participants.
	Finally, we recorded an impairment loss of approximately $15 million on certain of our buildings and land outside of the Oklahoma City and Fort Worth areas in 2013. All the buildings and land for which impairment losses were recognized in 2013, 2012 and 2011 are included in our other segment.
	Drilling Rigs and Equipment. In 2013, we negotiated the purchase of 23 leased rigs (two of which were classified as held for sale assets as of December 31, 2013) from various lessors for an aggregate purchase price of $141 million and paid approximately $22 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, we impaired approximately $22 million of leasehold improvements and other costs associated with these transactions. See Note 4 for a description of the master lease agreements. In addition, in 2013, we recognized $27 million of impairment losses on certain of our drilling rigs that qualified as held for sale during 2013 for the difference between the carrying amount and fair value, less the anticipated costs to sell. We estimated the fair value using prices expected to be received. In 2012, we negotiated the purchase of 25 leased rigs from various lessors for an aggregate purchase price of $36 million and paid approximately $25 million in early lease termination costs, which is included in impairments of fixed assets and other in the consolidated statement of operations. In addition, in 2012, we recognized $26 million of impairment losses on certain of our drilling rigs that we expected would have insufficient cash flow to recover carrying values because of a change in business climate resulting from depressed natural gas prices. We estimated the fair value of the drilling rigs using prices expected to be received from the sale of each rig in an orderly transaction between market participants. Also in 2012, we recognized $9 million of impairment losses primarily related to drill pipe and other oilfield services equipment. The drilling rigs and equipment are included in our oilfield services operating segment.
	Gathering Systems. In 2013, 2012 and 2011, we recognized approximately $22 million, $6 million and $43 million, respectively, of impairment losses on certain of our gathering systems classified as held for sale as of December 31, 2013 and 2012 based on decreases in the estimated fair value of these assets. We estimated the fair value of the gathering systems using prices expected to be received from the sale of each gathering system in an orderly transaction between market participants. These gathering systems are included in our marketing, gathering and compression operating segment.
	Other. In 2013, we recorded approximately $87 million of other charges, including $26 million for the termination of a gas gathering agreement, $28 million for the impairment of certain assets used to promote natural gas demand, $15 million for the termination of a contract drilling agreement with a third party, $2 million related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale and $16 million related to various other assets. In 2012, we recorded a $26 million charge related to the estimated 2012 shortfall of our net acreage maintenance commitment with Total in the Barnett Shale. See Commitments - Net Acreage Maintenance Commitments in Note 4 for further discussion.

Restructuring_and_Other_Termin

Restructuring and Other Termination Benefits (Note)	12 Months Ended
	Dec. 31, 2013
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Activities Disclosure [Text Block]	'
	Restructuring and Other Termination Costs
	On September 9, 2013, we committed to a workforce reduction plan as part of a company-wide reorganization effort intended to reduce costs. The reduction was communicated to affected employees on various dates within the months of September and October, and all such notifications were completed by October 11, 2013. The plan resulted in a reduction of approximately 900 employees. In connection with the reduction, we incurred a total cost of approximately $66 million.
	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. See Note 7 regarding Mr. McClendon’s historical participation in our drilling activities. In 2013, we incurred charges of approximately $69 million related to Mr. McClendon’s departure.
	In December 2012, Chesapeake announced that it had offered a voluntary separation program (VSP) to certain employees as part of the Company's ongoing efforts to improve efficiencies and reduce costs. The VSP was offered to approximately 275 employees who met criteria based upon a combination of age and years of Chesapeake service, and 211 accepted prior to the expiration of the offer in February 2013. We recognized the expense related to their termination benefits over their remaining service period which resulted in $63 million of expense for 2013.
	During 2013, we also incurred charges of approximately $50 million related to other workforce reductions, including separations of executive officers other than the CEO.
	Substantially all of the restructuring and other termination costs in 2013 are in the exploration and production operating segment. Below is a summary of our restructuring and other termination costs for the years ended December 31, 2013, 2012 and 2011:
		Years Ended December 31,
		2013		2012		2011
		($ in millions)
	Restructuring charges under workforce reduction plan:
	Salary expense	$	20	$	—	$	—
	Acceleration of stock-based compensation	45		—		—
	Other termination benefits	1		—		—
	Total restructuring charges	66		—		—
	under workforce reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense	11		—		—
	Acceleration of 2008 performance bonus clawback	11		—		—
	Acceleration of stock-based compensation	22		—		—
	Acceleration of performance share unit awards	18		—		—
	Estimated aircraft usage benefits	7		—		—
	Total termination benefits provided to	69		—		—
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense	33		1		—
	Acceleration of stock-based compensation	29		1		—
	Other termination benefits	1		—		—
	Total termination benefits provided to	63		2		—
	VSP participants
	Other termination benefits	50		5		—
	Total restructuring and other termination costs	$	248	$	7	$	—

Fair_Value_Measurements_Note

Fair Value Measurements (Note)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements Disclosure [Text Block]	'
	Fair Value Measurements
	Recurring Fair Value Measurement
	Other Current Assets. Assets related to forfeited 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.
	Investments. The fair value of Chesapeake’s investments in Clean Energy and Gastar common stock was based on quoted market prices.
	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.
	Derivatives. 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 fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2013 and 2012:
	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		)
	Derivatives:
	Commodity assets		—			25			15			40
	Commodity liabilities		—			(100		)	(493		)	(593		)
	Interest rate liabilities		—			(98		)	—			(98		)
	Foreign currency liabilities		—			2			—			2
	Total derivatives		—			(171		)	(478		)	(649		)
	Total		$	(2	)	$	(171	)	$	(478	)	$	(651	)
	As of December 31, 2012		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		$	4		$	—		$	—		$	4
	Investments		20			—			—			20
	Other long-term assets		88			—			—			88
	Other long-term liabilities		(87		)	—			—			(87		)
	Derivatives:
	Commodity assets		—			105			10			115
	Commodity liabilities		—			(13		)	(1,026		)	(1,039		)
	Interest rate liabilities		—			(35		)	—			(35		)
	Foreign currency liabilities		—			(20		)	—			(20		)
	Total derivatives		—			37			(1,016		)	(979		)
	Total		$	25		$	37		$	(1,016	)	$	(954	)
	A summary of the changes in Chesapeake’s financial assets (liabilities) classified as Level 3 measurements during 2013 and 2012 is presented below.
			Derivatives
			Commodity			Interest Rate
			($ in millions)
	Beginning Balance as of January 1, 2013		$	(1,016	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		410			(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—			1
	Settlements		128			—
	Ending Balance as of December 31, 2013		$	(478	)	$	—
	Beginning Balance as of January 1, 2012		$	(1,654	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		567			6
	Total purchases, issuances, sales and settlements:
	Sales		—			(6		)
	Settlements		71			—
	Ending Balance as of December 31, 2012		$	(1,016	)	$	—
	___________________________________________
	(a)		Natural Gas, Oil and						Interest Expense
			NGL Sales
			2013			2012			2013			2012
		($ in millions)
Total gains (losses) included in earnings for the period		$	410		$	567		$	(1	)	$	6
Change in unrealized gains (losses) related to assets still held at reporting date		$	382		$	374		$	—		$	—
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			December 31,
								2013
								($ in millions)
Oil trades(a)		Oil price volatility curves		0% - 23.65%	13.62		%	$	(265	)
Oil basis swaps(b)		Physical pricing point forward		$3.51 - $4.41	$	3.74		$	1
		curves
Natural gas trades(a)		Natural gas price volatility		17.75% - 60.88%	22.49		%	$	(217	)
		curves
Natural gas basis swaps(b)		Physical pricing point forward		($1.03) - ($0.11)	$	(0.46	)	$	3
		curves
____________________________________________
(a)	Fair value is based on an estimate derived from option models.
(b)	Fair value is based on an estimate of discounted cash flows.
Nonrecurring Fair Value Measurements
In 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. Fair value measurements were applied with respect to these non-financial assets, measured on a nonrecurring basis, to determine impairments. We used the income approach, specifically discounted cash flows, for income-producing assets and the market approach for the remaining assets. As the fair values estimated using the market approach were based on recent prices from orderly sales transactions for comparable properties between market participants, the values of these properties are classified as Level 2. The discounted cash flow method includes the development of both current operating metrics as well as assumptions pertaining to the subsequent change of such metrics, including rent growth, operating expense growth and absorption. These assumptions are applied to a specified period to develop future cash flow projections that are then discounted to estimate fair value. Due to these assumptions, the values of these properties are classified as Level 3.
Due to a decrease in the estimated market prices of certain surface land classified as held for sale in the Fort Worth, Texas area, we recognized an additional impairment loss in 2013. Fair value measurements were applied with respect to these non-financial assets, measured on a nonrecurring basis, to determine impairments. We measured the fair value of these assets by obtaining the current list price, if marketed for sale, or comparable list prices from similar properties in the area. The list prices were based on and adjusted for review of market data for comparable properties, where available, review of aerial or survey information, and assessment of other property and market-related factors. These list prices are estimates and are subject to changing market conditions. Should market conditions change adversely in the future, this could result in additional impairment or result in proceeds received upon sale to materially differ from the current estimate. See Note 16 for further discussion of the impairments recorded.
Fair Value of Other Financial Instruments
The following disclosure of the estimated fair value of financial instruments is made in accordance with accounting guidance for financial instruments. The carrying values of financial instruments comprising cash and cash equivalents, restricted cash, accounts payable and accounts receivable approximate fair values due to the short-term maturities of these 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-Dec-13						31-Dec-12
		Carrying			Estimated			Carrying			Estimated
		Amount			Fair Value			Amount			Fair Value
					($ in millions)
Current maturities of long-term debt (Level 1)		$	—		$	—		$	463		$	480
Long-term debt (Level 1)		$	10,501		$	11,557		$	9,759		$	10,457
Long-term debt (Level 2)		$	2,372		$	2,369		$	2,378		$	2,284

Asset_Retirement_Obligations_N

Asset Retirement Obligations (Note)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Asset Retirement Obligation Disclosure [Text Block]	'
	Asset Retirement Obligations
	The components of the change in our asset retirement obligations are shown below.
			Years Ended December 31,
			2013			2012
			($ in millions)
	Asset retirement obligations, beginning of period		$	375		$	323
	Additions		20			29
	Revisions(a)		8			42
	Settlements and disposals		(20		)	(41		)
	Accretion expense		22			22
	Asset retirement obligations, end of period		$	405		$	375
	_________________________________________
	(a)	Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement.

Segment_Information_Note

Segment Information (Note)	12 Months Ended
	Dec. 31, 2013
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]	'
Segment Information Disclosure [Text Block]	'
	Major Customers and Segment Information
	There were no sales to individual customers constituting 10% or more of total revenues (before the effects of hedging) for the years ended December 31, 2013 and 2011. Sales to Plains Marketing, L.P. constituted 11% of our total revenues (before the effects of hedging) for the year ended December 31, 2012.
	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 $7.570 billion, $5.464 billion and $5.246 billion for the years ended December 31, 2013, 2012 and 2011, 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 $1.309 billion, $1.315 billion and $737 million for the years ended December 31, 2013, 2012 and 2011, respectively. No income is recognized in our consolidated statements of operations related to oilfield services performed for Chesapeake-operated wells. The following table presents selected financial information for Chesapeake’s operating segments:
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Year Ended December 31, 2013:
	Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
	Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
	Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
	Unrealized gains on commodity derivatives	(228		)	—			—			—			—			(228		)
	Natural gas, oil, NGL and other depreciation, depletion and amortization	2,674			46			289			49			(155		)	2,903
	(Gains) losses on sales of fixed assets	2			(329		)	(1		)	26			—			(302		)
	Impairments of fixed assets and other	27			50			75			394			—			546
	Interest expense	(918		)	(24		)	(82		)	(74		)	871			(227		)
	Earnings (losses) on investments	3			—			(1		)	(229		)	1			(226		)
	Losses on sales of investments	—			—			—			(7		)	—			(7		)
	Losses on purchases of debt and extinguishment of other financing	(193		)	—			—			—			—			(193		)
	Income (Loss) Before	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	1,442
	Income Taxes
	Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
	Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Year Ended December 31, 2012:
	Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
	Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
	Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
	Unrealized gains on commodity derivatives	(561		)	—			—			—			—			(561		)
	Natural gas, oil, NGL and other depreciation, depletion and amortization	2,624			54			232			46			(145		)	2,811
	Impairment of natural gas and oil properties	3,315			—			—			—			—			3,315
	Impairments of fixed assets and other	28			6			60			246			—			340
	(Gains) losses on sales of fixed assets	14			(298		)	10			7			—			(267		)
	Interest expense	(47		)	(20		)	(76		)	(364		)	430			(77		)
	Earnings (losses) on investments	—			49			—			(152		)	—			(103		)
	Gains (losses) on sales of investments	(2		)	1,094			—			—			—			1,092
	Losses on purchases of debt and extinguishment of other financing	(200		)	—			—			—			—			(200		)
	Income (Loss) Before	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
	Income Taxes
	Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
	Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Year Ended December 31, 2011:
	Revenues	$	6,024		$	10,336		$	1,258		$	—		$	(5,983	)	$	11,635
	Intersegment revenues	—			(5,246		)	(737		)	—			5,983			—
	Total revenues	$	6,024		$	5,090		$	521		$	—		$	—		$	11,635
	Unrealized losses on commodity derivatives	789			—			—			—			—			789
	Natural gas, oil, NGL and other depreciation, depletion and amortization	1,759			55			172			37			(100		)	1,923
	Impairments of fixed assets and other	—			43			3			—			—			46
	(Gains) losses on sales of fixed assets	3			(441		)	1			—			—			(437		)
	Interest expense	(42		)	(15		)	(48		)	(195		)	256			(44		)
	Earnings on investments	—			95			—			61			—			156
	Losses on purchases of debt and extinguishment of other financing	(176		)	—			—			—			—			(176		)
Income (Loss) Before	$	2,561		$	745		$	72		$	(168	)	$	(330	)	$	2,880
Income Taxes
Total Assets	$	35,403		$	4,047		$	1,571		$	2,718		$	(1,904	)	$	41,835
Capital Expenditures	$	12,201		$	1,219		$	657		$	484		$	—		$	14,561

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information (Note)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	'
	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 subsidiary, COS, and its 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 referred to 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 December 31, 2013 and 2012 and for the years ended December 31, 2013, 2012 and 2011. 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. Certain prior year information has been restated for subsidiaries that have changed between guarantor and non-guarantor during 2013.
	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			2,395			613			(367		)	2,744
	Current assets held for sale		—			—			—			—			—
	Intercompany receivable, net		25,385			—			—			(25,385		)	—
	Total Current Assets		26,287			2,395			734			(25,760		)	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		—			2,317			1,495			(1		)	3,811
	Property and equipment held for sale, net		—			701			29			—			730
	Total Property and Equipment,		—			32,313			4,637			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,146			111			(376		)	992
	Investments in subsidiaries and		2,333			(235		)	—			(2,098		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,619		$	5,482		$	(28,050	)	$	41,782
	CURRENT LIABILITIES:
	Current liabilities		$	300		$	5,196		$	378		$	(359	)	$	5,515
	Intercompany payable, net		—			24,814			474			(25,288		)	—
	Total Current Liabilities		300			30,010			852			(25,647		)	5,515
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,831			—			1,055			—			12,886
	Deferred income tax liabilities		209			2,254			857			87			3,407
	Other long-term liabilities		396			1,022			877			(461		)	1,834
	Total Long-Term Liabilities		12,436			3,276			2,789			(374		)	18,127
	EQUITY:
	Chesapeake stockholders’ equity		15,995			2,333			1,841			(4,174		)	15,995
	Noncontrolling interests		—			—			—			2,145			2,145
	Total Equity		15,995			2,333			1,841			(2,029		)	18,140
	TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,619		$	5,482		$	(28,050	)	$	41,782
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2012
	($ in millions)
			Parent(a)			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries(a)			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	228		$	—		$	59		$	—		$	287
	Restricted cash		—			—			111			—			111
	Other		1			2,382			511			(348		)	2,546
	Current assets held for sale		—			—			4			—			4
	Intercompany receivable, net		25,159			—			—			(25,159		)	—
	Total Current Assets		25,388			2,382			685			(25,507		)	2,948
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			28,742			3,387			(211		)	31,918
	Other property and equipment, net		—			3,065			1,551			(1		)	4,615
	Property and equipment held for sale, net		—			256			378			—			634
	Total Property and Equipment,		—			32,063			5,316			(212		)	37,167
	Net
	LONG-TERM ASSETS:
	Other assets		217			1,396			261			(378		)	1,496
	Investments in subsidiaries and		2,438			(134		)	—			(2,304		)	—
	intercompany advances
	TOTAL ASSETS		$	28,043		$	35,707		$	6,262		$	(28,401	)	$	41,611
CURRENT LIABILITIES:
Current liabilities		$	789		$	5,377		$	428		$	(349	)	$	6,245
Current liabilities held for sale		—			—			21			—			21
Intercompany payable, net		—			23,684			1,586			(25,270		)	—
Total Current Liabilities		789			29,061			2,035			(25,619		)	6,266
LONG-TERM LIABILITIES:
Long-term debt, net		11,089			—			1,068			—			12,157
Deferred income tax liabilities		361			2,425			127			(106		)	2,807
Other liabilities		235			1,783			839			(372		)	2,485
Total Long-Term Liabilities		11,685			4,208			2,034			(478		)	17,449
EQUITY:
Chesapeake stockholders’ equity		15,569			2,438			2,193			(4,631		)	15,569
Noncontrolling interests		—			—			—			2,327			2,327
Total Equity		15,569			2,438			2,193			(2,304		)	17,896
TOTAL LIABILITIES AND EQUITY		$	28,043		$	35,707		$	6,262		$	(28,401	)	$	41,611
___________________________________________
(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 $228 million, which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AS OF DECEMBER 31, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	6,289		$	754		$	9		$	7,052
Marketing, gathering and compression		—			9,549			10			—			9,559
Oilfield services		—			—			2,218			(1,323		)	895
Total Revenues		—			15,838			2,982			(1,314		)	17,506
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			1,099			60			—			1,159
Production taxes		—			221			8			—			229
Marketing, gathering and compression		—			9,456			5			—			9,461
Oilfield services		—			95			1,761			(1,120		)	736
General and administrative		—			361			97			(1		)	457
Restructuring and other termination costs		—			244			4			—			248
Natural gas, oil and NGL depreciation,		—			2,303			286			—			2,589
depletion and amortization
Depreciation and amortization of other		—			177			292			(155		)	314
assets
Impairment of natural gas and oil		—			—			311			(311		)	—
properties
Impairments of fixed assets and other		—			443			103			—			546
Net gains on sales of fixed assets		—			(301		)	(1		)	—			(302		)
Total Operating Expenses		—			14,098			2,926			(1,587		)	15,437
INCOME (LOSS) FROM OPERATIONS		—			1,740			56			273			2,069
OTHER INCOME (EXPENSE):
Interest expense		(921		)	(4		)	(85		)	783			(227		)
Losses on investments		—			(225		)	(1		)	—			(226		)
Losses on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt and extinguishment of other financing		(70		)	(123		)	—			—			(193		)
Other income (loss)		3,979			(594		)	13			(3,372		)	26
Equity in net earnings of subsidiary		(1,129		)	(264		)	—			1,393			—
Total Other Income (Expense)		1,859			(1,217		)	(73		)	(1,196		)	(627		)
INCOME (LOSS) BEFORE INCOME		1,859			523			(17		)	(923		)	1,442
TAXES
INCOME TAX EXPENSE (BENEFIT)		1,135			299			(6		)	(880		)	548
NET INCOME (LOSS)		724			224			(11		)	(43		)	894
Net income attributable to		—			—			—			(170		)	(170		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		724			224			(11		)	(213		)	724
TO CHESAPEAKE
Other comprehensive income (loss)		3			19			(2		)	—			20
COMPREHENSIVE INCOME (LOSS)		$	727		$	243		$	(13	)	$	(213	)	$	744
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AS OF DECEMBER 31, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	5,819		$	387		$	72		$	6,278
Marketing, gathering and compression		—			5,370			212			(151		)	5,431
Oilfield services		—			—			1,941			(1,334		)	607
Total Revenues		—			11,189			2,540			(1,413		)	12,316
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			1,275			29			—			1,304
Production taxes		—			182			6			—			188
Marketing, gathering and compression		—			5,284			115			(87		)	5,312
Oilfield services		—			168			1,433			(1,136		)	465
General and administrative		—			415			121			(1		)	535
Restructuring and other termination costs		—			5			2			—			7
Natural gas, oil and NGL depreciation,		—			2,346			161			—			2,507
depletion and amortization
Depreciation and amortization of other		—			181			273			(150		)	304
assets
Impairment of natural gas and oil properties		—			3,174			141			—			3,315
Impairments of fixed assets and other		—			275			65			—			340
Net gains on sales of fixed assets		—			(269		)	2			—			(267		)
Total Operating Expenses		—			13,036			2,348			(1,374		)	14,010
INCOME (LOSS) FROM OPERATIONS		—			(1,847		)	192			(39		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense		(879		)	45			(84		)	841			(77		)
Losses on investments		—			(167		)	55			9			(103		)
Gains on sales of investments		—			1,030			62			—			1,092
Losses on purchases of debt and extinguishment of other financing		(200		)	—			—			—			(200		)
Other income		819			202			15			(1,028		)	8
Equity in net earnings (losses) of subsidiary		(610		)	(163		)	—			773			—
Total Other Income (Expense)		(870		)	947			48			595			720
INCOME (LOSS) BEFORE INCOME		(870		)	(900		)	240			556			(974		)
TAXES
INCOME TAX EXPENSE (BENEFIT)		(101		)	(287		)	93			(85		)	(380		)
NET INCOME (LOSS)		(769		)	(613		)	147			641			(594		)
Net income attributable to		—			—			—			(175		)	(175		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(769		)	(613		)	147			466			(769		)
TO CHESAPEAKE
Other comprehensive income (loss)		6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME (LOSS)		$	(763	)	$	(635	)	$	147		$	466		$	(785	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AS OF DECEMBER 31, 2011
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	5,886		$	84		$	54		$	6,024
Marketing, gathering and compression		—			5,022			199			(131		)	5,090
Oilfield services		—			18			1,260			(757		)	521
Total Revenues		—			10,926			1,543			(834		)	11,635
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			1,073			—			—			1,073
Production taxes		—			190			2			—			192
Marketing, gathering and compression		—			4,944			116			(93		)	4,967
Oilfield services		—			1			958			(557		)	402
General and administrative		—			477			71			—			548
Natural gas, oil and NGL depreciation,		—			1,625			7			—			1,632
depletion and amortization
Depreciation and amortization of other		—			169			217			(95		)	291
assets
Impairments of fixed assets and other		—			—			46			—			46
Net gains on sales of fixed assets		—			(2		)	(435		)	—			(437		)
Total Operating Expenses		—			8,477			982			(745		)	8,714
INCOME (LOSS) FROM OPERATIONS		—			2,449			561			(89		)	2,921
OTHER INCOME (EXPENSE):
Interest expense		(640		)	(12		)	(50		)	658			(44		)
Earnings (losses) on investments		—			61			95			—			156
Losses on purchases of debt and extinguishment of other financing		(176		)	—			—			—			(176		)
Other income		646			43			19			(685		)	23
Equity in net earnings of subsidiary		1,846			309			—			(2,155		)	—
Total Other Income (Expense)		1,676			401			64			(2,182		)	(41		)
INCOME (LOSS) BEFORE INCOME TAXES		1,676			2,850			625			(2,271		)	2,880
INCOME TAX EXPENSE (BENEFIT)		(66		)	991			243			(45		)	1,123
NET INCOME (LOSS)		1,742			1,859			382			(2,226		)	1,757
Net income attributable to		—			—			—			(15		)	(15		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		1,742			1,859			382			(2,241		)	1,742
TO CHESAPEAKE
Other comprehensive income		9			(9		)	2			—			2
COMPREHENSIVE INCOME (LOSS)		$	1,751		$	1,850		$	384		$	(2,241	)	$	1,744
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	4,115		$	542		$	(43	)	$	4,614
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(6,226		)	(410		)	—			(6,636		)
properties
Proceeds from divestitures of proved		—			3,414			53			—			3,467
and unproved properties
Additions to other property and		—			(581		)	(391		)	—			(972		)
equipment
Other investing activities		—			117			765			292			1,174
Net Cash Used In Investing Activities		—			(3,276		)	17			292			(2,967		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		—			6,452			1,217			—			7,669
borrowings
Payments on credit facilities borrowings		—			(6,452		)	(1,230		)	—			(7,682		)
Proceeds from issuance of senior notes,		2,274			—			—			—			2,274
net of discount and offering costs
Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
Proceeds from sales of noncontrolling		—			—			6			—			6
interests
Other financing activities		1,819			(2,809		)	17			(250		)	(1,223		)
Intercompany advances, net		(1,381		)	1,970			(589		)	—			—
Net Cash Provided By (Used In) Financing Activities		571			(839		)	(579		)	(250		)	(1,097		)
Net increase (decrease) in cash and cash		571			—			(20		)	(1		)	550
equivalents
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	799		$	—		$	39		$	(1	)	$	837
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2012
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	3,662		$	431		$	(1,256	)	$	2,837
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(11,099		)	(992		)	—			(12,091		)
properties
Proceeds from divestitures of proved		—			5,583			301			—			5,884
and unproved properties
Additions to other property and		—			(855		)	(1,796		)	—			(2,651		)
equipment
Other investing activities		—			4,705			2,133			(2,964		)	3,874
Net Cash Used In Investing Activities		—			(1,666		)	(354		)	(2,964		)	(4,984		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			18,336			1,982			—			20,318
Payments on credit facilities borrowings		—			(20,056		)	(1,594		)	—			(21,650		)
Proceeds from issuance of senior notes, net of discount and offering costs		1,263			—			—			—			1,263
Proceeds from issuance of term loans, net of discount and offering costs		5,722			—			—			—			5,722
Cash paid to purchase debt		(4,000		)	—			—			—			(4,000		)
Proceeds from sales of noncontrolling interests		—			—			1,077			—			1,077
Other financing activities		(477		)	(153		)	(4,237		)	4,220			(647		)
Intercompany advances, net		(2,282		)	(123		)	2,405			—			—
Net Cash Provided By (Used In) Financing Activities		226			(1,996		)	(367		)	4,220			2,083
Net increase in cash and cash equivalents		226			—			(290		)	—			(64		)
Cash and cash equivalents, beginning of		2			—			349			—			351
period
Cash and cash equivalents, end of period		$	228		$	—		$	59		$	—		$	287
___________________________________________
(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 $228 million, which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	5,868		$	438		$	(403	)	$	5,903
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(10,420		)	(2,021		)	—			(12,441		)
properties
Proceeds from divestitures of proved		—			7,651			—			—			7,651
and unproved properties
Additions to other property and		—			(520		)	(1,489		)	—			(2,009		)
equipment
Other investing activities		—			(348		)	719			616			987
Net Cash Used In Investing Activities		—			(3,637		)	(2,791		)	616			(5,812		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			14,005			1,504			—			15,509
Payments on credit facilities borrowings		—			(15,898		)	(1,568		)	—			(17,466		)
Proceeds from issuance of senior notes, net of discount and offering costs		977			—			637			—			1,614
Cash paid to purchase debt		(2,015		)	—			—			—			(2,015		)
Proceeds from sales of noncontrolling interests		—			—			1,348			—			1,348
Other financing activities		(494		)	1,413			462			(213		)	1,168
Intercompany advances, net		1,533			(1,751		)	218			—			—
Net Cash Provided By (Used In) Financing Activities		1			(2,231		)	2,601			(213		)	158
Net increase in cash and cash equivalents		1			—			248			—			249
Cash and cash equivalents, beginning of		1			—			101			—			102
period
Cash and cash equivalents, end of period		$	2		$	—		$	349		$	—		$	351
___________________________________________
(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 $2 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)	12 Months Ended
	Dec. 31, 2013
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	'
	Recently Issued Accounting Standards
	Recently Adopted Accounting Standards
	In February 2012, the Financial Accounting Standards Board (FASB) issued guidance changing the presentation requirements of significant reclassifications out of accumulated other comprehensive income in their entirety and their corresponding effect on net income. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements.
	In December 2011 and January 2013, the FASB issued guidance amending and expanding disclosure requirements about offsetting and related arrangements associated with derivatives. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements.
	Recently Issued Accounting Standards
	To reduce diversity in practice related to the presentation of unrecognized tax benefits, in July 2013 the FASB issued guidance requiring the presentation of an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward. This net presentation is required unless a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset to settle any additional income tax that would result from the disallowance of the unrecognized tax benefit. The guidance will be effective on January 1, 2014; retrospective application and early adoption are permitted, but not required. Because we have historically presented unrecognized tax benefits net of net operating loss carryforwards, similar tax losses or tax credit carryforwards, this standard will not impact our consolidated financial statements.
	In February 2013, the FASB issued guidance on the recognition, measurement and disclosure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. We will adopt this standard effective January 1, 2014. We do not expect the adoption to have a material impact on our consolidated financial statements.

Subsequent_Events_Note

Subsequent Events (Note)	12 Months Ended
	Dec. 31, 2013
Subsequent Events [Abstract]	'
Subsequent Events Disclosure [Text Block]	'
	Subsequent Events
	On January 13, 2014, we sold our investment in Chaparral Energy, Inc. for cash proceeds of $215 million.
	Subsequent to December 31, 2013, we acquired ten rigs subject to the master lease agreements described in Note 4. In conjunction with the purchases, we also terminated approximately $9 million of remaining lease commitments associated with these rigs. Total consideration paid was approximately $31 million and we anticipate recording a charge in the 2014 first quarter for lease termination cost.
	Subsequent to December 31, 2013, we acquired 576 compressors subject to the master lease agreements described in Note 4. In conjunction with these purchases, we also terminated approximately $126 million of remaining lease commitments associated with these compressors. Total consideration paid was approximately $168 million.

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

'

Basis of Accounting, Policy [Policy Text Block]

'

Basis of Presentation

The accompanying consolidated financial statements of Chesapeake 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.

Use of Estimates, Policy [Policy Text Block]

'

Accounting Estimates

The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Actual results could differ from those estimates.

Estimates of natural gas and oil reserves and their values, future production rates and future costs and expenses are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates.

Consolidation, Policy [Policy Text Block]

'

Consolidation

Chesapeake consolidates entities in which we have a controlling financial interest. We consolidate subsidiaries in which we hold, directly or indirectly, more than 50% of the voting rights and variable interest entities (VIEs) in which Chesapeake is the primary beneficiary. We use the equity method of accounting to record our net interests where Chesapeake has the ability to exercise significant influence through its investment in common stock. Under the equity method, our share of net income (loss) is included in our consolidated statements of operations according to our equity ownership or according to the terms of the applicable governing instrument. Investments in securities not accounted for under the equity method have been designated as available-for-sale and, as such, are carried at fair value whenever this value is readily determinable. Otherwise, the investment is carried at cost. See Note 13 for further discussion of our investments. Undivided interests in natural gas and oil exploration and production joint ventures are consolidated on a proportionate basis.

Noncontrolling Interests

Noncontrolling interests represent third-party equity ownership in certain of our consolidated subsidiaries and are presented as a component of equity. See Note 8 for further discussion of noncontrolling interests.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

'

Variable Interest Entities

VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.

Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both the consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 14 for further discussion of VIEs.

We consolidate the activities of VIEs for which we are the primary beneficiary.

Risks and Uncertainties [Policy Text Block]

'

Risks and Uncertainties

We have recently conducted a company-wide review of our operations, assets and organizational structure to best position the Company to maximize shareholder value going forward 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.

Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]

'

Cash and Cash Equivalents and Restricted Cash

For purposes of the consolidated financial statements, Chesapeake considers investments in all highly liquid instruments with original maturities of three months or less at date of purchase to be cash equivalents. Restricted cash consists of balances required to be maintained by the terms of the respective agreements governing the activities of CHK Utica, L.L.C. (CHK Utica) and CHK Cleveland Tonkawa, L.L.C. (CHK C-T). See Note 8 for further discussion of these entities.

Receivables, Policy [Policy Text Block]

'

Accounts Receivable

Our accounts receivable are primarily from purchasers of natural gas, oil and NGL and from exploration and production companies that own interests in properties we operate. This industry concentration could affect our overall exposure to credit risk, either positively or negatively, because our purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. We monitor the creditworthiness of all our counterparties and we generally require letters of credit or parent guarantees for receivables from parties which are judged to have sub-standard credit, unless the credit risk can otherwise be mitigated. We utilize an allowance method in accounting for bad debt based on historical trends in addition to specifically identifying receivables we believe will be uncollectible. During 2013, 2012 and 2011, we recognized $2 million, a nominal amount and $1 million of bad debt expense related to potentially uncollectible receivables, and we reduced our allowance by $3 million in 2013 as we wrote off specific receivables against our allowance. Accounts receivable as of December 31, 2013 and 2012 are detailed below.

December 31,

2013

2012

($ in millions)

Natural gas, oil and NGL sales

$

1,548

$

1,457

Joint interest

417

592

Oilfield services

63

24

Related parties(a)

62

23

Other

150

168

Allowance for doubtful accounts

(18

)

(19

)

Total accounts receivable, net

$

2,222

$

2,245

___________________________________________

(a)

See Note 7 for discussion of related party transactions.

Oil and Gas Properties Policy [Policy Text Block]

'

Natural Gas and Oil Properties

Chesapeake follows the full cost method of accounting under which all costs associated with natural gas and oil property acquisition, exploration and development activities are capitalized. We capitalize internal costs that can be directly identified with these activities and do not capitalize any costs related to production, general corporate overhead or similar activities (see Supplementary Information - Supplemental Disclosures About Natural Gas, Oil and NGL Producing Activities). Capitalized costs are amortized on a composite unit-of-production method based on proved natural gas and oil reserves. Estimates of our proved reserves as of December 31, 2013 were prepared by independent engineering firms and Chesapeake's internal staff. Approximately 81% of these proved reserves estimates (by volume) as of December 31, 2013 were prepared by independent engineering firms. In addition, our internal engineers review and update our reserves on a quarterly basis.

Proceeds from the sale of natural gas and oil properties are accounted for as reductions of capitalized costs unless such sales involve a significant change in proved reserves and significantly alter the relationship between costs and proved reserves, in which case a gain or loss is recognized.

The costs of unproved properties are excluded from amortization until the properties are evaluated. We review all of our unproved properties quarterly to determine whether or not and to what extent proved reserves have been assigned to the properties and otherwise if impairment has occurred. Unproved properties are grouped by major prospect area where individual property costs are not significant. In addition, we analyze our unproved leasehold and transfer to proved properties leasehold that can be associated with reserves, leasehold that expired in the quarter or leasehold that is not a part of our development strategy and will be abandoned.

The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2013 and the year in which the associated costs were incurred.

Year of Acquisition

2013

2012

2011

Prior

Total

($ in millions)

Leasehold acquisition cost

$

229

$

1,648

$

2,113

$

5,066

$

9,056

Exploration cost

623

341

93

8

1,065

Capitalized interest

667

516

270

439

1,892

Total

$

1,519

$

2,505

$

2,476

$

5,513

$

12,013

We also review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC. This quarterly review is referred to as a ceiling test. Under the ceiling test, capitalized costs, less accumulated amortization and related deferred income taxes, may not exceed an amount equal to the sum of the present value of estimated future net revenues (adjusted for natural gas and oil derivatives designated as cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. The ceiling test calculation uses costs as of the end of the applicable quarterly period and the unweighted arithmetic average of natural gas, oil and NGL prices on the first day of each month within the 12-month period prior to the ending date of the quarterly period. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts, including the effects of derivatives designated as cash flow hedges. As of December 31, 2013, none of our open derivative instruments were designated as cash flow hedges. Our natural gas and oil hedging activities are discussed in Note 11.

Two primary factors impacting the ceiling test are reserves levels and natural gas, oil and NGL prices, and their associated impact on the present value of estimated future net revenues. Revisions to estimates of natural gas and oil reserves and/or an extended increase or decrease in prices can have a material impact on the present value of estimated future net revenues. Any excess of the net book value is written off as an expense.

We account for seismic costs as part of our natural gas and oil properties (i.e., full cost pool). Exploration costs may be incurred both before acquiring the related property and after acquiring the property. Further, exploration costs include, among other things, geological and geophysical studies and salaries and other expenses of geologists, geophysical crews and others conducting those studies. Such costs are capitalized as incurred. The Company reviews its unproved properties and associated seismic costs quarterly to determine whether impairment has occurred. To the extent that seismic costs cannot be directly associated with specific unproved properties, they are included in the amortization base as incurred.

Property, Plant and Equipment, Policy [Policy Text Block]

'

Other Property and Equipment

Other property and equipment consists primarily of oilfield services equipment, including drilling rigs, rental tools and hydraulic fracturing equipment, natural gas compressors, buildings and improvements, land, vehicles, office equipment, natural gas and oil gathering systems and treating plants. Substantially all of our natural gas gathering systems and treating plants were sold in 2013 and 2012 as discussed in Note 15. Major renewals and betterments are capitalized while the costs of repairs and maintenance are charged to expense as incurred. The costs of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from the accounts, and the resulting gain or loss is reflected in operating costs. See Note 15 for further discussion of our gains and losses on the sales of other property and equipment and a summary of our other property and equipment held for sale as of December 31, 2013. Other property and equipment costs, excluding land, are depreciated on a straight-line basis.

Realization of the carrying value of other property and equipment is reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair value. An estimate of fair value is based on the best information available, including prices for similar assets and discounted cash flow. During 2013, 2012 and 2011, we determined that certain of our property and equipment was being carried at values that were not recoverable and in excess of fair value. See Note 16 for further discussion of these impairments.

Interest Capitalization, Policy [Policy Text Block]

'

Capitalized Interest

Interest from external borrowings is capitalized on significant projects until the asset is ready for service using the weighted average cost of outstanding borrowings. Capitalized interest is determined by multiplying our weighted-average borrowing cost on debt by the average amount of qualifying costs incurred. Capitalized interest is depreciated over the useful lives of the assets in the same manner as the depreciation of the underlying asset.

Goodwill and Intangible Assets, Goodwill, Policy [Policy Text Block]

'

Goodwill

Goodwill represents the excess of the purchase price of a business combination over the fair value of the net assets acquired and is tested for impairment at least annually. Such test includes an assessment of qualitative and quantitative factors. The impairment test requires allocating goodwill and all other assets and liabilities to assigned reporting units. The fair value of each reporting unit is estimated and compared to the net book value of the reporting unit. If the estimated fair value of the reporting unit is less than the net book value, including goodwill, then the goodwill is written down to the implied fair value of the goodwill through a charge to expense.

Our goodwill of $43 million as of December 31, 2013 and 2012 consisted of the excess consideration over the fair value of assets acquired of $28 million in our Bronco Drilling Company acquisition and $15 million in our Horizon Drilling Services acquisition. Quoted market prices are not available for these reporting units and their fair values are based upon several valuation analyses, including discounted cash flows. We performed annual impairment tests of goodwill in the fourth quarters of 2013 and 2012. Based on these assessments, no impairment of goodwill was required. Goodwill is included in our oilfield services segment.

Accounts Payable [Policy Text Block]

'

Accounts Payable

Included in accounts payable as of December 31, 2013 and 2012 are liabilities of approximately $397 million and $432 million, respectively, representing the amount by which checks issued, but not yet presented to our banks for collection, exceeded balances in applicable bank accounts.

Debt, Policy [Policy Text Block]

'

Debt Issuance and Hedging Facility Costs

Included in other long-term assets are costs associated with the issuance of our senior notes, term loan, revolving bank credit facilities and hedging facility. The remaining unamortized issuance costs as of December 31, 2013 and 2012 totaled $145 million and $182 million, respectively, and are being amortized over the life of the applicable debt or facility using the effective interest method.

Environmental Costs, Policy [Policy Text Block]

'

Environmental Remediation Costs

Chesapeake records environmental reserves for estimated remediation costs related to existing conditions from past operations when the responsibility to remediate is probable and the costs can be reasonably estimated. Expenditures that create future benefits or contribute to future revenue generation are capitalized.

Asset Retirement Obligations and Environmental Cost, Policy [Policy Text Block]

'

Asset Retirement Obligations

We recognize liabilities for retirement obligations associated with the retirement of tangible long-lived assets that result from the acquisition, construction and development of the assets. We recognize the fair value of a liability for a retirement obligation in the period in which the liability is incurred. For natural gas and oil properties, this is the period in which a natural gas or oil well is acquired or drilled. The liability is then accreted each period until the liability is settled or the well is sold, at which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our natural gas and oil properties. See Note 19 for further discussion of asset retirement obligations.

Revenue Recognition, Policy [Policy Text Block]

'

Revenue Recognition

Natural Gas, Oil and NGL Sales. Revenue from the sale of natural gas, oil and NGL is recognized when title passes, net of royalties due to third parties and gathering and transportation charges.

Natural Gas Imbalances. We follow the "sales method" of accounting for our natural gas revenue whereby we recognize sales revenue on all natural gas sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. An asset or a liability is recognized to the extent that we have an imbalance in excess of the remaining natural gas reserves on the underlying properties. The natural gas imbalance liability net position as of December 31, 2013 and 2012 was $11 million and $9 million, respectively.

Marketing, Gathering and Compression Sales. Chesapeake takes title to the natural gas, oil and NGL it purchases from other interest owners in operated wells at defined delivery points and delivers the product to third parties, at which time revenues are recorded. Chesapeake's results of operations related to its natural gas, oil and NGL marketing activities are presented on a "gross" basis, because we act as a principal rather than an agent. Gathering and compression revenues consist of fees billed to other interest owners in operated wells or third-party producers for the gathering, treating and compression of natural gas. Revenues are recognized when the service is performed and are based upon non-regulated rates and the related gathering, treating and compression volumes. All significant intercompany accounts and transactions have been eliminated.

Oilfield Services Revenue. Our oilfield services operating segment is responsible for contract drilling, hydraulic fracturing, oilfield rentals, oilfield trucking and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties.

•

Drilling. Revenues are generated by drilling oil and natural gas wells for our customers under daywork contracts and recognized for the days completed based on the dayrate specified in each contract. Revenue generated and costs incurred for mobilization services are recognized over the days of actual mobilization.

•

Hydraulic Fracturing. Revenue is recognized upon the completion of each fracturing stage. Typically one or more fracturing stages per day per active crew is completed during the course of a job. A stage is considered complete when the customer requests or the job design dictates that pumping discontinue for that stage. Invoices typically include a lump sum equipment charge determined by the rate per stage specified in each contract and product charges for sand, chemicals and other products actually consumed during the course of providing fracturing services.

•

Oilfield Rentals. Oilfield equipment rentals include drill pipe, drill collars, tubing, blowout preventers, and frac and mud tanks, and services include air drilling services and services associated with the transfer of fresh water to the wellsite. Rentals and services are priced by the day or hour based on the type of equipment being rented and the service job performed. Revenue is recognized ratably over the term of the rental.

•

Oilfield Trucking. Oilfield trucking provides rig relocation and logistics services as well as fluid handling services. Trucks move drilling rigs, crude oil, other fluids and construction materials to and from the wellsites and also transport produced water from the wellsites. These services are priced on a per barrel basis based on mileage and revenue is recognized as services are performed.

•

Other Operations. A manufacturing subsidiary designs, engineers and fabricates natural gas compressor packages that are purchased primarily by Chesapeake. Compression units are priced based on certain specifications such as horsepower, stages and additional options. Revenue is recognized upon completion and transfer of ownership of the natural gas compression unit.

Fair Value Measurement, Policy [Policy Text Block]

'

Fair Value Measurements

Certain financial instruments are reported at fair value on our consolidated balance sheets. Under fair value measurement accounting guidance, fair value is defined as the amount that would be received from the sale of an asset or paid for the transfer of a liability in an orderly transaction between market participants, i.e., an exit price. To estimate an exit price, a three-level hierarchy is used. The fair value hierarchy prioritizes the inputs, which refer broadly to assumptions market participants would use in pricing an asset or a liability, into three levels. Level 1 inputs are unadjusted quoted prices in active markets for identical assets and liabilities and have the highest priority. Level 2 inputs are inputs other than quoted prices within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability and have the lowest priority.

The valuation techniques that may be used to measure fair value include a market approach, an income approach and a cost approach. A market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. An income approach uses valuation techniques to convert future amounts to a single present amount based on current market expectations, including present value techniques, option-pricing models and the excess earnings method. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (replacement cost).

Derivatives, Policy [Policy Text Block]

'

Derivatives

Derivative instruments are recorded on the consolidated balance sheets as derivative assets or derivative liabilities at fair value, and changes in a derivative’s fair value are recognized currently in earnings unless specific hedge accounting criteria are met. For qualifying commodity derivative instruments designated as cash flow hedges, changes in fair value, to the extent the hedge is effective, are recognized in other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized immediately in earnings. Changes in the fair value of interest rate derivative instruments designated as fair value hedges are recorded on the consolidated balance sheets as assets or liabilities, and the debt's carrying value amount is adjusted by the change in the fair value of the debt subsequent to the initiation of the derivative. Differences between the changes in the fair values of the hedged item and the derivative instrument, if any, represent hedge effectiveness and are recognized currently in earnings.

We have elected not to designate any of our qualifying commodity and interest rate derivatives as cash flow or fair value hedges. Therefore, changes in fair value of these derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are recognized in the consolidated statements of operations within natural gas, oil and NGL sales and interest expense, respectively. Derivative instruments reflected as current in the consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivatives are deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying consolidated statement of cash flows. All of our derivative instruments are subject to master netting arrangements by contract type (i.e., commodity, interest rate and cross currency contracts) which provide for offsetting of asset and liability positions within each contract type, as well as related cash collateral if applicable, by counterparty. Therefore, we net the value of our derivative instruments by contract type with the same counterparty in the accompanying consolidated balance sheets.

We have established the fair value of our derivative instruments using established index prices, volatility curves and discount factors. These estimates are compared to our counterparty values for reasonableness. The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. Derivative transactions are subject to the risk that counterparties will be unable to meet their obligations. Such non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives. See Note 11 for further discussion of our derivative instruments.

Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]

'

Share-Based Compensation

Chesapeake’s share-based compensation program consists of restricted stock, stock options and performance share units granted to employees and restricted stock granted to non-employee directors under our Long Term Incentive Plan. We recognize in our financial statements the cost of employee services received in exchange for restricted stock and stock options based on the fair value of the equity instruments as of the grant date. For employees, this value is amortized over the vesting period, which is generally three or four years from the grant date. For directors, although restricted stock grants vest over three years, this value is recognized immediately as there is a non-substantive service condition for vesting. Because performance share units can only be settled in cash, they are classified as a liability in our consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. These fair value adjustments are recognized as compensation expense in the consolidated statements of operations.

To the extent compensation cost relates to employees directly involved in the acquisition of natural gas and oil leasehold and exploration and development activities, such amounts are capitalized to natural gas and oil properties. Amounts not capitalized to natural gas and oil properties are recognized as general and administrative expenses, natural gas, oil and NGL production expenses, marketing, gathering and compression expenses or oilfield services expenses, based on the employees involved in those activities.

Cash inflows resulting from tax deductions in excess of compensation expense recognized for stock options and restricted stock are classified as financing cash inflows, while reductions in tax benefits are classified as operating cash outflows in our consolidated statements of cash flows. See Note 9 for further discussion of share-based compensation.

Reclassification, Policy [Policy Text Block]

'

Reclassifications

Certain reclassifications have been made to the consolidated financial statements for 2012 and 2011 to conform to the presentation used for the 2013 consolidated financial statements.

Variable_Interest_Entities_Var

Variable Interest Entities Variable Interest Entity (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	'
	Variable Interest Entities
	VIEs are entities that, by design, either (i) lack sufficient equity to permit the entity to finance its activities independently, or (ii) have equity holders that do not have the power to direct the activities of the entity that most significantly impact its economic performance, the obligation to absorb the entity’s losses, or the right to receive the entity’s residual returns. We consolidate a VIE when we are the primary beneficiary, which is the party that has both (i) the power to direct the activities that most significantly impact the VIE’s economic performance and (ii) through its interests in the VIE, the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
	Along with a VIE that we consolidate, we also hold a variable interest in another VIE that is not consolidated because we are not the primary beneficiary. We continually monitor both the consolidated and unconsolidated VIEs to determine if any events have occurred that could cause the primary beneficiary to change. See Note 14 for further discussion of VIEs.
	We consolidate the activities of VIEs for which we are the primary beneficiary.

Impairment_Policies

Impairment (Policies)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	'
	We review, on a quarterly basis, the carrying value of our natural gas and oil properties under the full cost accounting rules of the SEC.

Recently_Issued_Accounting_Sta1

Recently Issued Accounting Standards Recently Issued Accounting Standards (Policies)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
New Accounting Pronouncements, Policy [Policy Text Block]	'
	Recently Adopted Accounting Standards
	In February 2012, the Financial Accounting Standards Board (FASB) issued guidance changing the presentation requirements of significant reclassifications out of accumulated other comprehensive income in their entirety and their corresponding effect on net income. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements.
	In December 2011 and January 2013, the FASB issued guidance amending and expanding disclosure requirements about offsetting and related arrangements associated with derivatives. We adopted this standard in the first quarter of 2013 and it did not have a material impact on our financial statements.
	Recently Issued Accounting Standards
	To reduce diversity in practice related to the presentation of unrecognized tax benefits, in July 2013 the FASB issued guidance requiring the presentation of an unrecognized tax benefit in the financial statements as a reduction to a deferred tax asset for a net operating loss carryforward, a similar tax loss or a tax credit carryforward. This net presentation is required unless a net operating loss carryforward, a similar tax loss or a tax credit carryforward is not available at the reporting date or the tax law of the jurisdiction does not require, and the entity does not intend to use, the deferred tax asset to settle any additional income tax that would result from the disallowance of the unrecognized tax benefit. The guidance will be effective on January 1, 2014; retrospective application and early adoption are permitted, but not required. Because we have historically presented unrecognized tax benefits net of net operating loss carryforwards, similar tax losses or tax credit carryforwards, this standard will not impact our consolidated financial statements.
	In February 2013, the FASB issued guidance on the recognition, measurement and disclosure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date. We will adopt this standard effective January 1, 2014. We do not expect the adoption to have a material impact on our consolidated financial statements.

Basis_of_Presentation_and_Summ2

Basis of Presentation and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]	'
	Accounts receivable as of December 31, 2013 and 2012 are detailed below.
			December 31,
			2013			2012
			($ in millions)
	Natural gas, oil and NGL sales		$	1,548		$	1,457
	Joint interest		417			592
	Oilfield services		63			24
	Related parties(a)		62			23
	Other		150			168
	Allowance for doubtful accounts		(18		)	(19		)
	Total accounts receivable, net		$	2,222		$	2,245
	___________________________________________
	(a)	See Note 7 for discussion of related party transactions.
Capitalized Costs Relating to Oil and Gas Producing Activities [Table Text Block]	'
	The table below sets forth the cost of unproved properties excluded from the amortization base as of December 31, 2013 and the year in which the associated costs were incurred.
			Year of Acquisition
			2013			2012			2011		Prior		Total
			($ in millions)
	Leasehold acquisition cost		$	229		$	1,648		$	2,113	$	5,066	$	9,056
	Exploration cost		623			341			93		8		1,065
	Capitalized interest		667			516			270		439		1,892
	Total		$	1,519		$	2,505		$	2,476	$	5,513	$	12,013

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]	'
	For the years ended December 31, 2013 and 2012, 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 these two years. 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 2013 and 2012:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Year Ended December 31, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	10	5
	Year Ended December 31, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	86	56
	5.75% cumulative convertible preferred stock (series A)	$	63	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	10	5
	4.50% cumulative convertible preferred stock	$	12	6
	Participating securities	$	—	5
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	'
	For the year ended December 31, 2011, 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 year ended December 31, 2011 is as follows:
		Income (Numerator)		Weighted	Per
				Average	Share
				Shares	Amount
				(Denominator)
		(in millions, except per share data)
	For the Year Ended December 31, 2011:
	Basic EPS	$	1,570	637	$	2.47
	Effect of Dilutive Securities:
	Assumed conversion as of the beginning of the period
	of preferred shares outstanding during the period:
	Common shares assumed issued for 5.75% cumulative convertible preferred stock	86		55
	Common shares assumed issued for 5.75% cumulative convertible preferred stock (series A)	63		39
	Common shares assumed issued for 5.00% cumulative convertible preferred stock (series 2005B)	11		5
	Common shares assumed issued for 4.50% cumulative convertible preferred stock	12		6
	Participating securities	—		9
	Outstanding stock options	—		1
	Diluted EPS	$	1,742	752	$	2.32

Debt_Tables

Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Debt [Table Text Block]	'
	Our long-term debt consisted of the following as of December 31, 2013 and 2012:
			December 31,
			2013				2012
			($ in millions)
	Term loan due 2017		$	2,000			$	2,000
	7.625% senior notes due 2013		—				464
	9.5% senior notes due 2015		1,265				1,265
	3.25% senior notes due 2016		500				—
	6.25% euro-denominated senior notes due 2017(a)		473				454
	6.5% senior notes due 2017		660				660
	6.875% senior notes due 2018		97				474
	7.25% senior notes due 2018		669				669
	6.625% senior notes due 2019(b)		650				650
	6.775% senior notes due 2019		—				1,300
	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				—
	5.75% senior notes due 2023		1,100				—
	2.75% contingent convertible senior notes due 2035(c)		396				396
	2.5% contingent convertible senior notes due 2037(c)		1,168				1,168
	2.25% contingent convertible senior notes due 2038(c)		347				347
	Corporate revolving bank credit facility		—				—
	Oilfield services revolving bank credit facility		405				418
	Discount on senior notes and term loan(d)		(357		)		(465		)
	Interest rate derivatives(e)		13				20
	Total debt, net		12,886				12,620
	Less current maturities of long-term debt, net(f)		—				(463		)
	Total long-term debt, net		$	12,886			$	12,157
	___________________________________________
	(a)	The principal amount shown is based on the exchange rate of $1.3743 to €1.00 and $1.3193 to €1.00 as of December 31, 2013 and 2012, respectively. See Note 11 for information on our related foreign currency derivatives.
	(b)	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.
	(c)	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 fourth quarter of 2013, 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 first 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 2013, 2012 or 2011. 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. We will pay contingent interest on the convertible senior notes after they have been outstanding at least ten years under certain conditions. 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
	(d)	Discount as of December 31, 2013 and 2012 included $303 million and $376 million, respectively, associated with the equity component of our contingent convertible senior notes. This discount is amortized based on an effective yield method. Discount also included $33 million and $40 million as of December 31, 2013 and 2012, respectively, associated with our term loan discussed further below.
	(e)	See Note 11 for further discussion related to these instruments.
	(f)	As of December 31, 2012, there was $1 million of discount associated with the 7.625% Senior Notes due 2013.
Schedule of Maturities of Long-term Debt [Table Text Block]	'
	Total principal amount of debt maturities, using the earliest conversion date for contingent convertible senior notes, for the five years ended after December 31, 2013 are as follows:
			Principal Amount
			of Debt Securities
			($ in millions)
	2014		$	—
	2015		1,661
	2016		905
	2017		4,301
	2018		1,113
	2019 and thereafter		5,250
	Total		$	13,230
Schedule of Line of Credit Facilities [Table Text Block]	'
	During 2013, 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 December 31, 2013		$	—			$	405
	Letters of credit outstanding as of December 31, 2013		$	23			$	—
	___________________________________________
	(a)	Co-borrowers are Chesapeake Exploration, L.L.C., Chesapeake Appalachia, L.L.C. and Chesapeake Louisiana, L.P.
	(b)	Borrower is COO.

Contingencies_and_Commitments_1

Contingencies and Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	'
	The aggregate undiscounted minimum future lease payments are presented below.
		December 31, 2013
		Rigs		Compressors		Other		Total
		($ in millions)
	2014	$	51	$	53	$	13	$	117
	2015	11		50		11		72
	2016	6		104		9		119
	2017	7		23		3		33
	2018	1		29		2		32
	After 2018	—		1		1		2
	Total	$	76	$	260	$	39	$	375
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, are presented below.
		December 31, 2013
		($ in millions)
	2014	$	2,002
	2015	1,829
	2016	1,921
	2017	1,948
	2018	1,762
	2019 - 2099	7,728
	Total	$	17,190
Schedule Of Future Payments For Drilling Contracts Table Text Block	'
	As of December 31, 2013, the aggregate undiscounted minimum future payments under these drilling rig commitments are presented below:
		December 31,
		2013
		($ in millions)
	2014	$	36
	2015	5
	Total	$	41

Other_Liabilities_Other_Liabil

Other Liabilities Other Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Other Liabilities [Abstract]	'
Other Current Liabilities [Table Text Block]	'
	Other current liabilities as of December 31, 2013 and 2012 are detailed below.
			December 31,
			2013		2012
			($ in millions)
	Revenues and royalties due others		$	1,409	$	1,337
	Accrued natural gas, oil and NGL drilling and production costs		457		525
	Joint interest prepayments received		464		749
	Accrued compensation and benefits		320		225
	Other accrued taxes		161		130
	Accrued dividends		101		101
	Other		599		674
	Total other current liabilities		$	3,511	$	3,741
Other Long-Term Liabilities [Table Text Block]	'
	Other long-term liabilities as of December 31, 2013 and 2012 are detailed below.
			December 31,
			2013		2012
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	250	$	275
	CHK C-T ORRI conveyance obligation(b)		149		164
	Financing obligations(c)		31		175
	Mortgages payable(d)		—		56
	Other		554		506
	Total other long-term liabilities		$	984	$	1,176
	____________________________________________
	(a)	$13 million and $18 million of the total $263 million and $293 million obligations are recorded in other current liabilities as of December 31, 2013 and December 31, 2012, respectively. See Note 8 for further discussion of the transaction.
	(b)	$12 million and $14 million of the total $161 million and $178 million obligations are recorded in other current liabilities as of December 31, 2013 and December 31, 2012, respectively. See Note 8 for further discussion of the transaction.
	(c)	As of December 31, 2012, this amount consisted primarily of an obligation related to 111 real estate surface properties in the Fort Worth, Texas area that we financed in 2009 for approximately $145 million and for which we entered into a 40-year master lease agreement whereby we agreed to lease the sites for approximately $15 million to $27 million annually. This lease transaction was recorded as a financing lease and the cash received was recorded with an offsetting long-term liability on the consolidated balance sheet. On November 1, 2013, we terminated the financing master lease agreement on the surface properties for $258 million and recorded a loss of approximately $123 million associated with the extinguishment.
	(d)	In 2009, we financed our regional Barnett Shale headquarters building in Fort Worth, Texas for net proceeds of approximately $54 million with a five-year term loan which had a floating interest rate of prime plus 275 basis points. In 2013, we prepaid the term loan in full without penalty. As of December 31, 2013, the building was classified as property and equipment held for sale on our consolidated balance sheet.

Income_Taxes_Income_Taxes_Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	'
	The components of the income tax provision (benefit) for each of the periods presented below are as follows:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Current
	Federal	$	—		$	—		$	—
	State	22			47			13
		22			47			13
	Deferred
	Federal	502			(358		)	1,044
	State	24			(69		)	66
		526			(427		)	1,110
	Total	$	548		$	(380	)	$	1,123
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	'
	The effective income tax expense (benefit) differed from the computed "expected" federal income tax expense on earnings before income taxes for the following reasons:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Income tax expense (benefit) at the federal statutory rate (35%)	$	505		$	(341	)	$	1,008
	State income taxes (net of federal income tax benefit)	38			(38		)	74
	Other	5			(1		)	41
	Total	$	548		$	(380	)	$	1,123
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	'
	The tax-effected temporary differences and tax loss carryforwards which comprise deferred taxes are as follows:
		Years Ended December 31,
		2013			2012
		($ in millions)
	Deferred tax liabilities:
	Natural gas and oil properties	$	(2,631	)	$	(1,999	)
	Other property and equipment	(371		)	(436		)
	Volumetric production payments	(1,216		)	(1,432		)
	Contingent convertible debt	(439		)	(416		)
	Deferred tax liabilities	(4,657		)	(4,283		)
	Deferred tax assets:
	Net operating loss carryforwards	535			711
	Derivative instruments	108			172
	Asset retirement obligations	153			142
	Investments	130			106
	Deferred stock compensation	66			47
	Accrued liabilities	120			90
	Noncontrolling interest liabilities	152			178
	Alternative minimum tax credits	317			225
	Other	40			55
	Deferred tax assets	1,621			1,726
	Valuation allowance	(148		)	(160		)
	Net deferred tax assets	1,473			1,566
	Net deferred tax assets (liabilities)	$	(3,184	)	$	(2,717	)
	Reflected in accompanying balance sheets as:
	Current deferred income tax asset	$	223		$	90
	Non-current deferred income tax liability	(3,407		)	(2,807		)
	Total	$	(3,184	)	$	(2,717	)
Summary of Operating Loss Carryforwards [Table Text Block]	'
	The following table summarizes our federal and AMT NOLs as of December 31, 2013 and any related limitations:
		Total			Total Limitation			Annual Limitation
		($ in millions)
	Federal net operating loss	$	592		$	49		$	15
	AMT net operating loss	$	650		$	35		$	15
Summary of Unrecognized Tax Benefits Roll Forward [Table Text Block]	'
	A reconciliation of the beginning and ending balances of unrecognized tax benefits is as follows:
		2013			2012			2011
		($ in millions)
	Unrecognized tax benefits at beginning of period	$	599		$	369		$	34
	Additions based on tax positions related to the current year	15			134			135
	Additions to tax positions of prior years	30			96			200
	Settlements	—			—			—
	Unrecognized tax benefits at end of period	$	644		$	599		$	369

Related_Party_Related_Party_Ta

Related Party Related Party (Tables)	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Schedule of Related Party Transactions [Table Text Block]	'
	Other than Mr. McClendon, only our equity method investees were considered related parties. During 2013, 2012 and 2011, we had the following related party transactions with our equity method investees.
			Years Ended December 31,
			2013		2012		2011
			($ in millions)
	Purchases(a)		$	—	$	73	$	—
	Sales(b)		$	666	$	392	$	171
	Services(c)		$	397	$	480	$	369
	___________________________________________
	(a)	Purchase of equipment from FTS.
	(b)	In 2013, 2012 and 2011, Chesapeake sold produced gas to our 30%-owned investee, Twin Eagle Resource Management LLC.
	(c)	Hydraulic fracturing and other services provided to us by FTS in the ordinary course of business. As well operators, we are reimbursed by other working interest owners through the joint interest billing process for their proportionate share of these costs.
	The table below shows the total related party amounts due from and due to our equity method investees.
			December 31,
			2013		2012		2011
			($ in millions)
	Amounts due from equity method investment related parties		$	47	$	67	$	29
	Amounts due to equity method investment related parties		$	1	$	42	$	115

Equity_Tables

Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Common Stock [Table Text Block]	'
	The following is a summary of the changes in our common shares issued for 2013, 2012 and 2011:
			Years Ended December 31,
			2013			2012			2011
			(in thousands)
	Shares issued as of January 1		666,468			660,888			655,251
	Restricted stock issuances (net of forfeitures)(a)		(599	)		5,038			4,961
	Stock option exercises		323			542			565
	Preferred stock conversion		—			—			111
	Shares issued as of December 31		666,192			666,468			660,888
	___________________________________________
	(a)	In 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 Preferred Stock Summary and Conversion Terms [Table Text Block]	'
	Following is a summary of our preferred stock, including the primary conversion terms as of December 31, 2013:
	Preferred Stock Series		Issue Date		Liquidation				Holder's Conversion Right		Conversion Rate		Conversion Price				Company's	Company's Market Conversion Trigger(a)
					Preference												Conversion
					per Share												Right From
	5.75% cumulative		May and		$	1,000			Any time		37.185		$	26.8926			May 17, 2015	$	34.9604
	convertible		Jun-10
	non-voting
	5.75% (series A)		May		$	1,000			Any time		35.9339		$	27.8289			May 17, 2015	$	36.1776
	cumulative		2010
	convertible
	non-voting
	4.50% cumulative convertible		Sep-05		$	100			Any time		2.2969		$	43.5375			September 15, 2010	$	56.5988
	5.00% cumulative convertible (series 2005B)		Nov-05		$	100			Any time		2.599		$	38.4757			November 15, 2010	$	50.0184
	___________________________________________
	(a)	Convertible at the Company's option if the trading price of the Company's common stock equals or exceeds the trigger price for a specified time period or after the conversion date indicated if there are less than 250,000 shares of 4.50% or 5.00% (series 2005B) preferred stock outstanding or 25,000 shares of 5.75% or 5.75% (series A) preferred stock outstanding.
Preferred Stock Shares Outstanding [Table Text Block]	'
	The following reflects the shares outstanding of our preferred stock for 2013, 2012 and 2011:
			5.75%			5.75% (A)			4.50%			5.00%
												(2005B)
			(in thousands)
	Shares outstanding as of January 1, 2013 and December 31, 2013		1,497			1,100			2,559			2,096
	Shares outstanding as of January 1, 2012 and December 31, 2012		1,497			1,100			2,559			2,096
	Shares outstanding as of January 1, 2011		1,500			1,100			2,559			2,096
	Conversion of preferred shares into common stock		(3	)		—			—			—
	Shares outstanding at December 31, 2011		1,497			1,100			2,559			2,096
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	For the year ended December 31, 2013, 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, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		20				4				24
	Net current period other comprehensive income		22				(2		)		20
	Balance, December 31, 2013		$	(167	)		$	5			$	(162	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
			Years Ended December 31,
			2013								2012							2011
			Before				After				Before				After			Before			After
			Tax				Tax				Tax				Tax			Tax			Tax
			($ in millions)
	Balance, beginning of period		$	(304	)		$	(189	)		$	(287	)		$	(178	)	$	(291	)	$	(181	)
	Net change in fair value		3				2				10				6			368			228
	(Gains) losses reclassified to income		32				20				(27		)		(17		)	(364		)	(225		)
	Balance, end of period		$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	'
	For the year ended December 31, 2013, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the consolidated statement of operations are detailed below.
	Details About Accumulated		Affected Line Item		Year Ended
	Other Comprehensive		in the Statement		31-Dec-13
	Income (Loss) Components		Where Net Income is Presented
					($ in millions)
	Net losses on cash flow hedges:
	Commodity contracts		Natural gas, oil and NGL revenues		$	20
	Investments:
	Impairment of investment		Impairment of investment		6
	Sale of investment		Gain on sale of investment		(2		)
	Total reclassifications for the period, net of tax				$	24
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	For the years ended December 31, 2013 and 2012, the Trust declared and paid the following distributions:
	Production Period		Distribution Date		Cash Distribution				Cash Distribution
					per				per
					Common Unit				Subordinated Unit
	June 2013 - August 2013		November 29, 2013		$	0.6671			$	—
	March 2013 - May 2013		August 29, 2013		$	0.69			$	0.1432
	December 2012 - February 2013		May 31, 2013		$	0.69			$	0.301
	September 2012 - November 2012		March 1, 2013		$	0.67			$	0.3772
	June 2012 - August 2012		November 29, 2012		$	0.63			$	0.2208
	March 2012 - May 2012		August 30, 2012		$	0.61			$	0.4819
	December 2011 - February 2012		May 31, 2012		$	0.6588			$	0.6588
	September 2011 - November 2011		March 1, 2012		$	0.7277			$	0.7277

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Stock-Based Compensation [Table Text Block]	'
	We recorded the following compensation related to restricted stock and stock options during the years ended December 31, 2013, 2012 and 2011:
			Years Ended December 31,
			2013			2012			2011
			($ in millions)
	Natural gas and oil properties		$	52		$	71		$	112
	General and administrative expenses		60			71			92
	Natural gas, oil and NGL production expenses		21			24			33
	Marketing, gathering and compression expenses		7			15			17
	Oilfield services expenses		10			10			11
	Total		$	150		$	191		$	265
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 2013, 2012 and 2011 is presented below.
			Number of		Weighted Average
			Unvested		Grant Date
			Restricted Shares		Fair Value
			(in thousands)
	Unvested shares as of January 1, 2013		18,899		$	23.72
	Granted		9,189		$	19.68
	Vested		(12,897	)	$	21.32
	Forfeited		(1,791	)	$	22.86
	Unvested shares as of December 31, 2013		13,400		$	23.38
	Unvested shares as of January 1, 2012		19,544		$	26.97
	Granted		9,480		$	21.13
	Vested		(8,620	)	$	28.08
	Forfeited		(1,505	)	$	24.57
	Unvested shares as of December 31, 2012		18,899		$	23.72
	Unvested shares as of January 1, 2011		21,375		$	28.68
	Granted		9,541		$	28.38
	Vested		(10,401	)	$	31.76
	Forfeited		(971	)	$	27.28
	Unvested shares as of December 31, 2011		19,544		$	26.97
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	'
	The Company used the following weighted-average assumptions to estimate the fair value of the stock options granted in 2013:
	Expected option life - years		6.49
	Volatility		48.47	%
	Risk-free interest rate		1.3	%
	Dividend yield		1.82	%
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	'
	The following table provides information related to stock option activity for 2013, 2012 and 2011:
			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, 2013		481		$	12.69		0.96		$	2
	Granted		5,264		$	19.32
	Exercised		(346	)	$	10.82				$	11
	Expired		(131	)	$	19.31
	Outstanding at December 31, 2013		5,268		$	19.28		6.66		$	41
	Exercisable at December 31, 2013		1,552		$	18.82		1.97		$	13
	Outstanding at January 1, 2012		1,051		$	9.84		1.41		$	13
	Exercised		(570	)	$	7.45				$	7
	Outstanding and exercisable at December 31, 2012		481		$	12.69		0.96		$	2
	Outstanding at January 1, 2011		1,808		$	8.9		2.03		$	31
	Exercised		(757	)	$	7.59				$	15
	Outstanding and exercisable at December 31, 2011		1,051		$	9.84		1.41		$	13
	___________________________________________
	(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 December 31, 2013:
			Units		Fair Value			Fair Value				Liability for
					as of							Vested
					Grant Date							Amount
					($ in millions)
	2012 Awards (a)
	Payable 2014		278,083		$	8		$	11			$	11
	Payable 2015		834,248		23			31				30
	Total 2012 Awards		1,112,331		$	31		$	42			$	41
	2013 Awards
	Payable 2016		1,600,438		$	35		$	58			$	49
	___________________________________________
	(a)	In 2013, we paid $2 million related to 2012 PSU awards.
Schedule of Share-based Compensation, PSU Units, Activity [Table Text Block]	'
	We recorded the following compensation related to PSUs during the years ended December 31, 2013, 2012 and 2011:
			Years Ended December 31,
			2013			2012			2011
			($ in millions)
	Natural gas and oil properties		$	9		$	4		$	—
	General and administrative expenses		34			8			—
	Natural gas, oil and NGL production expenses		2			1			—
	Marketing, gathering and compression expenses		2			1			—
	Oilfield services expenses		1			—			—
	Total		$	48		$	14		$	—

Derivative_and_Hedging_Activit1

Derivative and Hedging Activities (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [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 December 31, 2013 and 2012 are provided below.
		31-Dec-13							31-Dec-12
		Volume			Fair Value				Volume			Fair Value
					($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps	448			$	(23	)		49			$	24
	Three-way collars	288			(7		)		—			—
	Call options	193			(210		)		193			(240		)
	Call swaptions	12			—				—			—
	Basis protection swaps	68			3				111			(15		)
	Total natural gas	1,009			(237		)		353			(231		)
	Oil (mmbbl):
	Fixed-price swaps	25.3			(50		)		28.1			68
	Call options	42.5			(265		)		73.8			(748		)
	Call swaptions	—			—				5.3			(13		)
	Basis protection swaps	0.4			1				5.5			—
	Total oil	68.2			(314		)		112.7			(693		)
	Total estimated fair value				$	(551	)					$	(924	)
Schedule of Derivative Instruments [Table Text Block]	'
	The components of natural gas, oil and NGL sales for the years ended December 31, 2013, 2012 and 2011 are presented below.
		Years Ended December 31,
		2013				2012				2011
		($ in millions)
	Natural gas, oil and NGL sales	$	6,923			$	5,359			$	5,259
	Gains on natural gas, oil and NGL derivatives	129				919				772
	Losses on ineffectiveness of cash flow hedges	—				—				(7		)
	Total natural gas, oil and NGL sales	$	7,052			$	6,278			$	6,024
Schedule of Interest Rate Derivatives [Table Text Block]	'
	The notional amount and the estimated fair value of our interest rate derivative liabilities as of December 31, 2013 and 2012 are provided below.
		31-Dec-13								31-Dec-12
		Notional				Fair				Notional				Fair
		Amount				Value				Amount				Value
						($ in millions)
	Interest rate swaps	$	2,250			$	(98	)		$	1,050			$	(35	)
Interest Income And Interest Expense Disclosure [Table Text Block]	'
	The components of interest expense for the years ended 2013, 2012 and 2011 are presented below.
		Years Ended December 31,
		2013				2012				2011
		($ in millions)
	Interest expense on senior notes	$	740			$	732			$	653
	Interest expense on credit facilities	38				70				70
	Interest expense on term loans	116				173				—
	(Gains) losses on interest rate derivatives	58				(7		)		14
	Amortization of loan discount, issuance costs and other	91				89				39
	Capitalized interest	(816		)		(980		)		(732		)
	Total interest expense	$	227			$	77			$	44
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 disclosed in the consolidated balance sheets as of December 31, 2013 and 2012 on a gross basis without regard to same-counterparty netting:
				Fair Value
				December 31,
		Balance Sheet Location		2013				2012
				($ in millions)
	Asset Derivatives:
	Designated as hedging instruments:
	Foreign currency contracts	Long-term derivative instruments		$	2			$	—
	Total			2				—
	Not designated as hedging instruments:
	Commodity contracts	Short-term derivative instruments		29				110
	Commodity contracts	Long-term derivative instruments		11				5
	Total			40				115
	Liability Derivatives:
	Designated as hedging instruments:
	Foreign currency contracts	Long-term derivative instruments		—				(20		)
	Total			—				(20		)
	Not designated as hedging instruments:
	Commodity contracts	Short-term derivative instruments		(231		)		(157		)
	Commodity contracts	Long-term derivative instruments		(362		)		(882		)
	Interest rate contracts	Short-term derivative instruments		(6		)		—
	Interest rate contracts	Long-term derivative instruments		(92		)		(35		)
	Total			(691		)		(1,074		)
	Total derivative instruments			$	(649	)		$	(979	)
Schedule of Net Investment Hedges, Statements of Financial Performance and Financial Position, Location [Table Text Block]	'
	The following tables present the netting offsets of derivative assets and liabilities in the consolidated balance sheets as of December 31, 2013 and December 31, 2012:
		31-Dec-13
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
	Commodity Contracts:
	Gross amounts of recognized assets (liabilities)	$	29			$	11			$	(231	)		$	(362	)
	Gross amounts offset in the consolidated balance sheet	(29		)		(9		)		29				9
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	—				2				(202		)		(353		)
	Interest Rate Contracts:
	Gross amounts of recognized assets (liabilities)	—				—				(6		)		(92		)
	Gross amounts offset in the consolidated balance sheet	—				—				—				—
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	—				—				(6		)		(92		)
	Foreign Currency Contracts:
	Gross amounts of recognized assets (liabilities)	—				2				—				—
	Gross amounts offset in the consolidated balance sheet	—				—				—				—
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	—				2				—				—
	Total derivatives as reported	$	—			$	4			$	(208	)		$	(445	)
		31-Dec-12
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
	Commodity Contracts:
	Gross amounts of recognized assets (liabilities)	$	110			$	5			$	(157	)		$	(882	)
	Gross amounts offset in the consolidated balance sheet	(52		)		(3		)		52				3
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	58				2				(105		)		(879		)
	Interest Rate Contracts:
	Gross amounts of recognized assets (liabilities)	—				—				—				(35		)
	Gross amounts offset in the consolidated balance sheet	—				—				—				—
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	—				—				—				(35		)
	Foreign Currency Contracts:
	Gross amounts of recognized assets (liabilities)	—				—				—				(20		)
	Gross amounts offset in the consolidated balance sheet	—				—				—				—
	Net amounts of assets (liabilities) presented in the consolidated balance sheet	—				—				—				(20		)
	Total derivatives as reported	$	58			$	2			$	(105	)		$	(934	)
Schedule Of Derivative Instruments, Gain (Loss) In Statement Of Financial Performance [Table Text Block]	'
	The following table presents the gain (loss) recognized in our consolidated statements of operations for terminated instruments that were designated as fair value derivatives:
				Years Ended December 31,
	Fair Value Derivatives	Location of Gain (Loss)		2013				2012				2011
				($ in millions)
	Interest rate contracts	Interest expense		$	5			$	8			$	16
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	For the year ended December 31, 2013, 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, 2012	$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications	2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income	20				4				24
	Net current period other comprehensive income	22				(2		)		20
	Balance, December 31, 2013	$	(167	)		$	5			$	(162	)
	A reconciliation of the changes in accumulated other comprehensive income (loss) in our consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Years Ended December 31,
		2013								2012							2011
		Before				After				Before				After			Before			After
		Tax				Tax				Tax				Tax			Tax			Tax
		($ in millions)
	Balance, beginning of period	$	(304	)		$	(189	)		$	(287	)		$	(178	)	$	(291	)	$	(181	)
	Net change in fair value	3				2				10				6			368			228
	(Gains) losses reclassified to income	32				20				(27		)		(17		)	(364		)	(225		)
	Balance, end of period	$	(269	)		$	(167	)		$	(304	)		$	(189	)	$	(287	)	$	(178	)
Schedule Of Cash Flow Hedge Hedges Included in AOCI [Table Text Block]	'
	The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) related to instruments designated as cash flow derivatives:
				Years Ended December 31,
	Cash Flow Derivatives	Location of Gain (Loss)		2013				2012				2011
				($ in millions)
	Gain (Loss) Recognized in AOCI (Effective Portion):
	Commodity contracts	AOCI		$	—			$	—			$	392
	Foreign currency contracts	AOCI		3				10				(24		)
				$	3			$	10			$	368
	Gain (Loss) Reclassified from AOCI (Effective Portion):
	Commodity contracts	Natural gas, oil and NGL sales		$	(32	)		$	27			$	402
	Foreign currency contracts	Interest expense		—				—				(18		)
	Foreign currency contacts	Loss on purchase of debt		—				—				(20		)
				$	(32	)		$	27			$	364
	Gain (Loss) Recognized in Income:
	Ineffective portion	Natural gas, oil and NGL sales		$	—			$	—			$	(7	)
	Amount initially excluded from effectiveness testing	Natural gas, oil and NGL sales		—				—				22
				$	—			$	—			$	15
Derivatives Not Designated As Hedging Instruments Disclosure [Table Text Block]	'
	The following table presents the gain (loss) recognized in our consolidated statements of operations for instruments not designated as either cash flow or fair value hedges:
				Years Ended December 31,
	Derivative Contracts	Location of Gain (Loss)		2013				2012				2011
				($ in millions)
	Commodity contracts	Natural gas, oil and NGL		$	159			$	892			$	348
	Interest rate contracts	Interest expense		(63		)		(1		)		(12		)
	Total			$	96			$	891			$	336

Natural_Gas_and_Oil_Property_D1

Natural Gas and Oil Property Divestitures (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [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			596
	Niobrara		CNOOC	Feb-11		33.30%		570				697		(f)	1,267			135
	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		$	731
	____________________________________________
	(a)	Joint venture partners include 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 December 31, 2013.
	(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 $90 million received at closing for closing adjustments.
	(e)	The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.
	(f)	The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration.
VPP Transactions [Table Text Block]	'
	Our outstanding VPPs consist of the following:
										Volume Sold
	VPP #		Date of VPP	Location		Proceeds				Natural Gas			Oil		NGL		Total
						($ 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 Texas		180				44			0.3		—		46
				Gulf Coast
	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 during 2013, 2012 and 2011 were as follows:
			Year Ended December 31, 2013
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		13.5		547			1,509.00			25.8
	9		17		213.2			455.7			21
	8		68.1		—			—			68.1
	6		4.8		24			—			4.9
	5		7.5		25.4			—			7.7
	4		10.2		54.7			—			10.5
	3		8.1		—			—			8.1
	2		10.3		—			—			10.3
	1		14.5		—			—			14.5
			154		864.3			1,964.70			170.9
			Year Ended December 31, 2012
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		18.1		727			1,729.10			32.8
	9		18.4		249.3			643.6			23.7
	8		79.7		—			—			79.7
	7		0.4		490.3			—			3.4
	6		5.3		24			—			5.5
	5		8.8		27.4			—			9
	4		11.7		62.8			—			12.2
	3		9.3		—			—			9.3
	2		11.4		—			—			11.3
	1		15.3		—			—			15.3
			178.4		1,580.80			2,372.70			202.2
			Year Ended December 31, 2011
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		—		—			—			—
	9		17.3		250.5			615.4			22.5
	8		101.2		—			—			101.2
	7		0.4		773			—			5
	6		6		27			—			6.2
	5		11		35.9			—			11.2
	4		13.8		75.1			—			14.3
	3		10.7		—			—			10.7
	2		12.5		—			—			12.5
	1		16.3		—			—			16.3
			189.2		1,161.50			615.4			199.9
VPP Volumes Remaining to be Delivered [Table Text Block]	'
	The volumes remaining to be delivered on behalf of our VPP buyers as of December 31, 2013 were as follows:
				Volume Remaining as of December 31, 2013
	VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
			(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
	10		98	48.6			1.7			6			94.8
	9		86	88.7			1			2.3			108.9
	8		20	96.5			—			—			96.5
	6		73	21.4			0.2			—			22.3
	5		37	16.9			0.1			—			17.2
	4		36	24.3			0.1			—			25.1
	3		67	31.1			—			—			31.1
	2		64	20			—			—			20
	1		108	105.4			—			—			105.4
				452.9			3.1			8.3			521.3

Investments_Tables

Investments (Tables)	12 Months Ended
	Dec. 31, 2013
Text Block [Abstract]	'
Investment Holdings, Schedule of Investments [Table Text Block]	'
	A summary of our investments, including our approximate ownership percentage as of December 31, 2013 and 2012, is presented below.
				Approximate			Carrying
				Ownership %			Value
		Accounting		December 31,			December 31,
		Method		2013	2012		2013				2012
							($ in millions)
	FTS International, Inc.	Equity		30%	30%		$	138			$	298
	Chaparral Energy, Inc.	Equity		20%	20%		143				141
	Sundrop Fuels, Inc.	Equity		56%	50%		135				111
	Clean Energy Fuels Corp.	Fair Value		—%	1%		—				12
	(common stock)
	Clean Energy Fuels Corp.	Cost		—%	—%		—				100
	(convertible notes)
	Gastar Exploration Ltd.	Fair Value		—%	10%		—				8
	Other	—		—%	—%		61				58
	Total investments						$	477			$	728
Equity Method Investments [Table Text Block]	'
	The table below presents summarized financial information for our significant equity method investments, including FTS and Sundrop. The investee financial information reflects the most current financial information available to investors and includes lags in financial reporting of up to one quarter.
		Years Ended December 31,
		2013			2012				2011
		($ in millions)
	Current assets	$	521		$	892			$	732
	Noncurrent assets	$	1,859		$	4,225			$	5,175
	Current liabilities	$	192		$	207			$	277
	Noncurrent liabilities	$	1,468		$	1,726			$	1,916
	Gross revenue	$	1,807		$	2,190			$	2,209
	Operating expense	$	3,926		$	3,089			$	1,630
	Net income (loss)	$	(2,459	)	$	(968	)		$	494

Other_Property_and_Equipment_T

Other Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment [Table Text Block]	'
	A summary of other property and equipment held for use and the useful lives thereof is as follows:
		December 31,						Useful
		2013			2012			Life
		($ in millions)						(in years)
	Oilfield services equipment	$	2,192		$	2,130		15-Mar
	Buildings and improvements	1,433			1,580			Oct-39
	Natural gas compressors	368			505			20-Mar
	Land	212			515			—
	Other	1,190			1,178			20-Feb
	Total other property and equipment, at cost	5,395			5,908
	Less: accumulated depreciation	(1,584		)	(1,293		)
	Total other property and equipment, net	$	3,811		$	4,615
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 years ended December 31, 2013, 2012 and 2011 is as follows:
		Years Ended December 31,
		2013			2012			2011
		($ in millions)
	Gathering systems and treating plants	$	(326	)	$	(286	)	$	(440	)
	Drilling rigs and equipment	2			10			1
	Buildings and land	27			7			2
	Other	(5		)	2			—
	Total net gains on sales of fixed assets	$	(302	)	$	(267	)	$	(437	)
Schedule Of Assets-held-for Sale [Table Text Block]	'
	A summary of the assets and liabilities held for sale on our consolidated balance sheets as of December 31, 2013 and 2012 is detailed below.
		December 31,
		2013			2012
		($ in millions)
	Accounts receivable	$	—		$	4
	Current assets held for sale	$	—		$	4
	Natural gas gathering systems and treating plants, net of accumulated depreciation	$	11		$	352
	Oilfield services equipment, net of accumulated depreciation	29			27
	Compressors, net of accumulated depreciation	285			—
	Buildings and land, net of accumulated depreciation	405			255
	Property and equipment held for sale, net	$	730		$	634
	Accounts payable	$	—		$	4
	Accrued liabilities	—			17
	Current liabilities held for sale	$	—		$	21

Impairments_Tables

Impairments (Tables)	12 Months Ended
	Dec. 31, 2013
Investments, Debt and Equity Securities [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 years ended December 31, 2013, 2012 and 2011 is as follows:
		Years Ended December 31,
		2013		2012		2011
		($ in millions)
	Buildings and land	$	366	$	248	$	3
	Drilling rigs and equipment	71		60		—
	Gathering systems	22		6		43
	Other	87		26		—
	Total impairments of fixed assets and other	$	546	$	340	$	46

Recovered_Sheet1

Restructuring and other Termination Benefits (Tables)	12 Months Ended
	Dec. 31, 2013
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 years ended December 31, 2013, 2012 and 2011:
		Years Ended December 31,
		2013		2012		2011
		($ in millions)
	Restructuring charges under workforce reduction plan:
	Salary expense	$	20	$	—	$	—
	Acceleration of stock-based compensation	45		—		—
	Other termination benefits	1		—		—
	Total restructuring charges	66		—		—
	under workforce reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense	11		—		—
	Acceleration of 2008 performance bonus clawback	11		—		—
	Acceleration of stock-based compensation	22		—		—
	Acceleration of performance share unit awards	18		—		—
	Estimated aircraft usage benefits	7		—		—
	Total termination benefits provided to	69		—		—
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense	33		1		—
	Acceleration of stock-based compensation	29		1		—
	Other termination benefits	1		—		—
	Total termination benefits provided to	63		2		—
	VSP participants
	Other termination benefits	50		5		—
	Total restructuring and other termination costs	$	248	$	7	$	—

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Of Assets and Liabilities Measured On A Recurring Basis [Table Text Block]	'
	The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis as of December 31, 2013 and 2012:
	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		)
	Derivatives:
	Commodity assets		—			25			15			40
	Commodity liabilities		—			(100		)	(493		)	(593		)
	Interest rate liabilities		—			(98		)	—			(98		)
	Foreign currency liabilities		—			2			—			2
	Total derivatives		—			(171		)	(478		)	(649		)
	Total		$	(2	)	$	(171	)	$	(478	)	$	(651	)
	As of December 31, 2012		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		$	4		$	—		$	—		$	4
	Investments		20			—			—			20
	Other long-term assets		88			—			—			88
	Other long-term liabilities		(87		)	—			—			(87		)
	Derivatives:
	Commodity assets		—			105			10			115
	Commodity liabilities		—			(13		)	(1,026		)	(1,039		)
	Interest rate liabilities		—			(35		)	—			(35		)
	Foreign currency liabilities		—			(20		)	—			(20		)
	Total derivatives		—			37			(1,016		)	(979		)
	Total		$	25		$	37		$	(1,016	)	$	(954	)
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	'
	A summary of the changes in Chesapeake’s financial assets (liabilities) classified as Level 3 measurements during 2013 and 2012 is presented below.
			Derivatives
			Commodity			Interest Rate
			($ in millions)
	Beginning Balance as of January 1, 2013		$	(1,016	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		410			(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—			1
	Settlements		128			—
	Ending Balance as of December 31, 2013		$	(478	)	$	—
	Beginning Balance as of January 1, 2012		$	(1,654	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		567			6
	Total purchases, issuances, sales and settlements:
	Sales		—			(6		)
	Settlements		71			—
	Ending Balance as of December 31, 2012		$	(1,016	)	$	—
	___________________________________________
	(a)		Natural Gas, Oil and						Interest Expense
			NGL Sales
			2013			2012			2013			2012
			($ in millions)
	Total gains (losses) included in earnings for the period		$	410		$	567		$	(1	)	$	6
	Change in unrealized gains (losses) related to assets still held at reporting date		$	382		$	374		$	—		$	—
Quantitative Disclosures About Unobservable Inputs For Level 3 Fair Value Measurements [Table Text Block]	'
	Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements
	Instrument		Unobservable		Range	Weighted			Fair Value
	Type		Input			Average			December 31,
									2013
									($ in millions)
	Oil trades(a)		Oil price volatility curves		0% - 23.65%	13.62		%	$	(265	)
	Oil basis swaps(b)		Physical pricing point forward		$3.51 - $4.41	$	3.74		$	1
			curves
	Natural gas trades(a)		Natural gas price volatility		17.75% - 60.88%	22.49		%	$	(217	)
			curves
	Natural gas basis swaps(b)		Physical pricing point forward		($1.03) - ($0.11)	$	(0.46	)	$	3
			curves
	____________________________________________
	(a)	Fair value is based on an estimate derived from option models.
	(b)	Fair value is based on an estimate of discounted cash flows.
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-Dec-13						31-Dec-12
			Carrying			Estimated			Carrying			Estimated
			Amount			Fair Value			Amount			Fair Value
						($ in millions)
	Current maturities of long-term debt (Level 1)		$	—		$	—		$	463		$	480
	Long-term debt (Level 1)		$	10,501		$	11,557		$	9,759		$	10,457
	Long-term debt (Level 2)		$	2,372		$	2,369		$	2,378		$	2,284

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation Disclosure [Abstract]	'
Schedule of Change in Asset Retirement Obligation [Table Text Block]	'
	The components of the change in our asset retirement obligations are shown below.
			Years Ended December 31,
			2013			2012
			($ in millions)
	Asset retirement obligations, beginning of period		$	375		$	323
	Additions		20			29
	Revisions(a)		8			42
	Settlements and disposals		(20		)	(41		)
	Accretion expense		22			22
	Asset retirement obligations, end of period		$	405		$	375
	_________________________________________
	(a)	Revisions in estimated liabilities during the period relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives, and the expected timing of settlement.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [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)
	Year Ended December 31, 2013:
	Revenues	$	7,052		$	17,129		$	2,188		$	29		$	(8,892	)	$	17,506
	Intersegment revenues	—			(7,570		)	(1,309		)	(13		)	8,892			—
	Total revenues	$	7,052		$	9,559		$	879		$	16		$	—		$	17,506
	Unrealized gains on commodity derivatives	(228		)	—			—			—			—			(228		)
	Natural gas, oil, NGL and other depreciation, depletion and amortization	2,674			46			289			49			(155		)	2,903
	(Gains) losses on sales of fixed assets	2			(329		)	(1		)	26			—			(302		)
	Impairments of fixed assets and other	27			50			75			394			—			546
	Interest expense	(918		)	(24		)	(82		)	(74		)	871			(227		)
	Earnings (losses) on investments	3			—			(1		)	(229		)	1			(226		)
	Losses on sales of investments	—			—			—			(7		)	—			(7		)
	Losses on purchases of debt and extinguishment of other financing	(193		)	—			—			—			—			(193		)
	Income (Loss) Before	$	2,997		$	511		$	(51	)	$	(727	)	$	(1,288	)	1,442
	Income Taxes
	Total Assets	$	35,341		$	2,430		$	2,018		$	5,750		$	(3,757	)	$	41,782
	Capital Expenditures	$	6,198		$	299		$	272		$	421		$	—		$	7,190
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Year Ended December 31, 2012:
	Revenues	$	6,278		$	10,895		$	1,917		$	21		$	(6,795	)	$	12,316
	Intersegment revenues	—			(5,464		)	(1,315		)	(16		)	6,795			—
	Total revenues	$	6,278		$	5,431		$	602		$	5		$	—		$	12,316
	Unrealized gains on commodity derivatives	(561		)	—			—			—			—			(561		)
	Natural gas, oil, NGL and other depreciation, depletion and amortization	2,624			54			232			46			(145		)	2,811
	Impairment of natural gas and oil properties	3,315			—			—			—			—			3,315
	Impairments of fixed assets and other	28			6			60			246			—			340
	(Gains) losses on sales of fixed assets	14			(298		)	10			7			—			(267		)
	Interest expense	(47		)	(20		)	(76		)	(364		)	430			(77		)
	Earnings (losses) on investments	—			49			—			(152		)	—			(103		)
	Gains (losses) on sales of investments	(2		)	1,094			—			—			—			1,092
	Losses on purchases of debt and extinguishment of other financing	(200		)	—			—			—			—			(200		)
	Income (Loss) Before	$	(1,798	)	$	1,665		$	112		$	(478	)	$	(475	)	$	(974	)
	Income Taxes
	Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611
	Capital Expenditures	$	12,044		$	852		$	658		$	554		$	—		$	14,108
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Year Ended December 31, 2011:
	Revenues	$	6,024		$	10,336		$	1,258		$	—		$	(5,983	)	$	11,635
	Intersegment revenues	—			(5,246		)	(737		)	—			5,983			—
	Total revenues	$	6,024		$	5,090		$	521		$	—		$	—		$	11,635
	Unrealized losses on commodity derivatives	789			—			—			—			—			789
	Natural gas, oil, NGL and other depreciation, depletion and amortization	1,759			55			172			37			(100		)	1,923
	Impairments of fixed assets and other	—			43			3			—			—			46
	(Gains) losses on sales of fixed assets	3			(441		)	1			—			—			(437		)
	Interest expense	(42		)	(15		)	(48		)	(195		)	256			(44		)
	Earnings on investments	—			95			—			61			—			156
	Losses on purchases of debt and extinguishment of other financing	(176		)	—			—			—			—			(176		)
	Income (Loss) Before	$	2,561		$	745		$	72		$	(168	)	$	(330	)	$	2,880
	Income Taxes
	Total Assets	$	35,403		$	4,047		$	1,571		$	2,718		$	(1,904	)	$	41,835
Capital Expenditures	$	12,201		$	1,219		$	657		$	484		$	—		$	14,561

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule of Condensed Balance Sheet [Table Text Block]	'
	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			2,395			613			(367		)	2,744
	Current assets held for sale		—			—			—			—			—
	Intercompany receivable, net		25,385			—			—			(25,385		)	—
	Total Current Assets		26,287			2,395			734			(25,760		)	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		—			2,317			1,495			(1		)	3,811
	Property and equipment held for sale, net		—			701			29			—			730
	Total Property and Equipment,		—			32,313			4,637			184			37,134
	Net
	LONG-TERM ASSETS:
	Other assets		111			1,146			111			(376		)	992
	Investments in subsidiaries and		2,333			(235		)	—			(2,098		)	—
	intercompany advances
	TOTAL ASSETS		$	28,731		$	35,619		$	5,482		$	(28,050	)	$	41,782
	CURRENT LIABILITIES:
	Current liabilities		$	300		$	5,196		$	378		$	(359	)	$	5,515
	Intercompany payable, net		—			24,814			474			(25,288		)	—
	Total Current Liabilities		300			30,010			852			(25,647		)	5,515
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,831			—			1,055			—			12,886
	Deferred income tax liabilities		209			2,254			857			87			3,407
	Other long-term liabilities		396			1,022			877			(461		)	1,834
	Total Long-Term Liabilities		12,436			3,276			2,789			(374		)	18,127
	EQUITY:
	Chesapeake stockholders’ equity		15,995			2,333			1,841			(4,174		)	15,995
	Noncontrolling interests		—			—			—			2,145			2,145
	Total Equity		15,995			2,333			1,841			(2,029		)	18,140
	TOTAL LIABILITIES AND EQUITY		$	28,731		$	35,619		$	5,482		$	(28,050	)	$	41,782
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF DECEMBER 31, 2012
	($ in millions)
			Parent(a)			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries(a)			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	228		$	—		$	59		$	—		$	287
	Restricted cash		—			—			111			—			111
	Other		1			2,382			511			(348		)	2,546
	Current assets held for sale		—			—			4			—			4
	Intercompany receivable, net		25,159			—			—			(25,159		)	—
	Total Current Assets		25,388			2,382			685			(25,507		)	2,948
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			28,742			3,387			(211		)	31,918
	Other property and equipment, net		—			3,065			1,551			(1		)	4,615
	Property and equipment held for sale, net		—			256			378			—			634
	Total Property and Equipment,		—			32,063			5,316			(212		)	37,167
	Net
	LONG-TERM ASSETS:
	Other assets		217			1,396			261			(378		)	1,496
	Investments in subsidiaries and		2,438			(134		)	—			(2,304		)	—
	intercompany advances
	TOTAL ASSETS		$	28,043		$	35,707		$	6,262		$	(28,401	)	$	41,611
	CURRENT LIABILITIES:
	Current liabilities		$	789		$	5,377		$	428		$	(349	)	$	6,245
	Current liabilities held for sale		—			—			21			—			21
Intercompany payable, net		—			23,684			1,586			(25,270		)	—
Total Current Liabilities		789			29,061			2,035			(25,619		)	6,266
LONG-TERM LIABILITIES:
Long-term debt, net		11,089			—			1,068			—			12,157
Deferred income tax liabilities		361			2,425			127			(106		)	2,807
Other liabilities		235			1,783			839			(372		)	2,485
Total Long-Term Liabilities		11,685			4,208			2,034			(478		)	17,449
EQUITY:
Chesapeake stockholders’ equity		15,569			2,438			2,193			(4,631		)	15,569
Noncontrolling interests		—			—			—			2,327			2,327
Total Equity		15,569			2,438			2,193			(2,304		)	17,896
TOTAL LIABILITIES AND EQUITY		$	28,043		$	35,707		$	6,262		$	(28,401	)	$	41,611
___________________________________________
(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 $228 million, which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.
Schedule of Condensed Income Statement [Table Text Block]	'
	CONSOLIDATING STATEMENT OF OPERATIONS
	AS OF DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	6,289		$	754		$	9		$	7,052
	Marketing, gathering and compression		—			9,549			10			—			9,559
	Oilfield services		—			—			2,218			(1,323		)	895
	Total Revenues		—			15,838			2,982			(1,314		)	17,506
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			1,099			60			—			1,159
	Production taxes		—			221			8			—			229
	Marketing, gathering and compression		—			9,456			5			—			9,461
	Oilfield services		—			95			1,761			(1,120		)	736
	General and administrative		—			361			97			(1		)	457
	Restructuring and other termination costs		—			244			4			—			248
	Natural gas, oil and NGL depreciation,		—			2,303			286			—			2,589
	depletion and amortization
	Depreciation and amortization of other		—			177			292			(155		)	314
	assets
	Impairment of natural gas and oil		—			—			311			(311		)	—
	properties
	Impairments of fixed assets and other		—			443			103			—			546
	Net gains on sales of fixed assets		—			(301		)	(1		)	—			(302		)
	Total Operating Expenses		—			14,098			2,926			(1,587		)	15,437
	INCOME (LOSS) FROM OPERATIONS		—			1,740			56			273			2,069
	OTHER INCOME (EXPENSE):
	Interest expense		(921		)	(4		)	(85		)	783			(227		)
	Losses on investments		—			(225		)	(1		)	—			(226		)
	Losses on sales of investments		—			(7		)	—			—			(7		)
	Losses on purchases of debt and extinguishment of other financing		(70		)	(123		)	—			—			(193		)
	Other income (loss)		3,979			(594		)	13			(3,372		)	26
	Equity in net earnings of subsidiary		(1,129		)	(264		)	—			1,393			—
	Total Other Income (Expense)		1,859			(1,217		)	(73		)	(1,196		)	(627		)
	INCOME (LOSS) BEFORE INCOME		1,859			523			(17		)	(923		)	1,442
	TAXES
	INCOME TAX EXPENSE (BENEFIT)		1,135			299			(6		)	(880		)	548
	NET INCOME (LOSS)		724			224			(11		)	(43		)	894
	Net income attributable to		—			—			—			(170		)	(170		)
	noncontrolling interests
	NET INCOME (LOSS) ATTRIBUTABLE		724			224			(11		)	(213		)	724
	TO CHESAPEAKE
	Other comprehensive income (loss)		3			19			(2		)	—			20
	COMPREHENSIVE INCOME (LOSS)		$	727		$	243		$	(13	)	$	(213	)	$	744
	ATTRIBUTABLE TO CHESAPEAKE
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	AS OF DECEMBER 31, 2012
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	5,819		$	387		$	72		$	6,278
	Marketing, gathering and compression		—			5,370			212			(151		)	5,431
	Oilfield services		—			—			1,941			(1,334		)	607
	Total Revenues		—			11,189			2,540			(1,413		)	12,316
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			1,275			29			—			1,304
	Production taxes		—			182			6			—			188
	Marketing, gathering and compression		—			5,284			115			(87		)	5,312
	Oilfield services		—			168			1,433			(1,136		)	465
General and administrative		—			415			121			(1		)	535
Restructuring and other termination costs		—			5			2			—			7
Natural gas, oil and NGL depreciation,		—			2,346			161			—			2,507
depletion and amortization
Depreciation and amortization of other		—			181			273			(150		)	304
assets
Impairment of natural gas and oil properties		—			3,174			141			—			3,315
Impairments of fixed assets and other		—			275			65			—			340
Net gains on sales of fixed assets		—			(269		)	2			—			(267		)
Total Operating Expenses		—			13,036			2,348			(1,374		)	14,010
INCOME (LOSS) FROM OPERATIONS		—			(1,847		)	192			(39		)	(1,694		)
OTHER INCOME (EXPENSE):
Interest expense		(879		)	45			(84		)	841			(77		)
Losses on investments		—			(167		)	55			9			(103		)
Gains on sales of investments		—			1,030			62			—			1,092
Losses on purchases of debt and extinguishment of other financing		(200		)	—			—			—			(200		)
Other income		819			202			15			(1,028		)	8
Equity in net earnings (losses) of subsidiary		(610		)	(163		)	—			773			—
Total Other Income (Expense)		(870		)	947			48			595			720
INCOME (LOSS) BEFORE INCOME		(870		)	(900		)	240			556			(974		)
TAXES
INCOME TAX EXPENSE (BENEFIT)		(101		)	(287		)	93			(85		)	(380		)
NET INCOME (LOSS)		(769		)	(613		)	147			641			(594		)
Net income attributable to		—			—			—			(175		)	(175		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(769		)	(613		)	147			466			(769		)
TO CHESAPEAKE
Other comprehensive income (loss)		6			(22		)	—			—			(16		)
COMPREHENSIVE INCOME (LOSS)		$	(763	)	$	(635	)	$	147		$	466		$	(785	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
AS OF DECEMBER 31, 2011
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	5,886		$	84		$	54		$	6,024
Marketing, gathering and compression		—			5,022			199			(131		)	5,090
Oilfield services		—			18			1,260			(757		)	521
Total Revenues		—			10,926			1,543			(834		)	11,635
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			1,073			—			—			1,073
Production taxes		—			190			2			—			192
Marketing, gathering and compression		—			4,944			116			(93		)	4,967
Oilfield services		—			1			958			(557		)	402
General and administrative		—			477			71			—			548
Natural gas, oil and NGL depreciation,		—			1,625			7			—			1,632
depletion and amortization
Depreciation and amortization of other		—			169			217			(95		)	291
assets
Impairments of fixed assets and other		—			—			46			—			46
Net gains on sales of fixed assets		—			(2		)	(435		)	—			(437		)
Total Operating Expenses		—			8,477			982			(745		)	8,714
INCOME (LOSS) FROM OPERATIONS		—			2,449			561			(89		)	2,921
OTHER INCOME (EXPENSE):
Interest expense		(640		)	(12		)	(50		)	658			(44		)
Earnings (losses) on investments		—			61			95			—			156
Losses on purchases of debt and extinguishment of other financing		(176		)	—			—			—			(176		)
Other income		646			43			19			(685		)	23
Equity in net earnings of subsidiary		1,846			309			—			(2,155		)	—
Total Other Income (Expense)		1,676			401			64			(2,182		)	(41		)
INCOME (LOSS) BEFORE INCOME TAXES		1,676			2,850			625			(2,271		)	2,880
INCOME TAX EXPENSE (BENEFIT)		(66		)	991			243			(45		)	1,123
NET INCOME (LOSS)		1,742			1,859			382			(2,226		)	1,757
Net income attributable to		—			—			—			(15		)	(15		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		1,742			1,859			382			(2,241		)	1,742
TO CHESAPEAKE
Other comprehensive income		9			(9		)	2			—			2
COMPREHENSIVE INCOME (LOSS)		$	1,751		$	1,850		$	384		$	(2,241	)	$	1,744
ATTRIBUTABLE TO CHESAPEAKE
Schedule of Condensed Cash Flow Statement [Table Text Block]	'
	CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	4,115		$	542		$	(43	)	$	4,614
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Acquisitions of proved and unproved		—			(6,226		)	(410		)	—			(6,636		)
	properties
	Proceeds from divestitures of proved		—			3,414			53			—			3,467
	and unproved properties
	Additions to other property and		—			(581		)	(391		)	—			(972		)
	equipment
	Other investing activities		—			117			765			292			1,174
	Net Cash Used In Investing Activities		—			(3,276		)	17			292			(2,967		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facilities		—			6,452			1,217			—			7,669
	borrowings
	Payments on credit facilities borrowings		—			(6,452		)	(1,230		)	—			(7,682		)
	Proceeds from issuance of senior notes,		2,274			—			—			—			2,274
	net of discount and offering costs
	Cash paid to purchase debt		(2,141		)	—			—			—			(2,141		)
	Proceeds from sales of noncontrolling		—			—			6			—			6
	interests
	Other financing activities		1,819			(2,809		)	17			(250		)	(1,223		)
	Intercompany advances, net		(1,381		)	1,970			(589		)	—			—
	Net Cash Provided By (Used In) Financing Activities		571			(839		)	(579		)	(250		)	(1,097		)
	Net increase (decrease) in cash and cash		571			—			(20		)	(1		)	550
	equivalents
	Cash and cash equivalents, beginning of		228			—			59			—			287
	period
	Cash and cash equivalents, end of period		$	799		$	—		$	39		$	(1	)	$	837
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	YEAR ENDED DECEMBER 31, 2012
	($ in millions)
			Parent(a)			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries(a)			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	3,662		$	431		$	(1,256	)	$	2,837
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Acquisitions of proved and unproved		—			(11,099		)	(992		)	—			(12,091		)
	properties
	Proceeds from divestitures of proved		—			5,583			301			—			5,884
	and unproved properties
	Additions to other property and		—			(855		)	(1,796		)	—			(2,651		)
	equipment
	Other investing activities		—			4,705			2,133			(2,964		)	3,874
	Net Cash Used In Investing Activities		—			(1,666		)	(354		)	(2,964		)	(4,984		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facilities borrowings		—			18,336			1,982			—			20,318
	Payments on credit facilities borrowings		—			(20,056		)	(1,594		)	—			(21,650		)
	Proceeds from issuance of senior notes, net of discount and offering costs		1,263			—			—			—			1,263
	Proceeds from issuance of term loans, net of discount and offering costs		5,722			—			—			—			5,722
	Cash paid to purchase debt		(4,000		)	—			—			—			(4,000		)
	Proceeds from sales of noncontrolling interests		—			—			1,077			—			1,077
	Other financing activities		(477		)	(153		)	(4,237		)	4,220			(647		)
	Intercompany advances, net		(2,282		)	(123		)	2,405			—			—
	Net Cash Provided By (Used In) Financing Activities		226			(1,996		)	(367		)	4,220			2,083
	Net increase in cash and cash equivalents		226			—			(290		)	—			(64		)
Cash and cash equivalents, beginning of		2			—			349			—			351
period
Cash and cash equivalents, end of period		$	228		$	—		$	59		$	—		$	287
___________________________________________
(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 $228 million, which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31, 2011
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	5,868		$	438		$	(403	)	$	5,903
CASH FLOWS FROM INVESTING
ACTIVITIES:
Acquisitions of proved and unproved		—			(10,420		)	(2,021		)	—			(12,441		)
properties
Proceeds from divestitures of proved		—			7,651			—			—			7,651
and unproved properties
Additions to other property and		—			(520		)	(1,489		)	—			(2,009		)
equipment
Other investing activities		—			(348		)	719			616			987
Net Cash Used In Investing Activities		—			(3,637		)	(2,791		)	616			(5,812		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			14,005			1,504			—			15,509
Payments on credit facilities borrowings		—			(15,898		)	(1,568		)	—			(17,466		)
Proceeds from issuance of senior notes, net of discount and offering costs		977			—			637			—			1,614
Cash paid to purchase debt		(2,015		)	—			—			—			(2,015		)
Proceeds from sales of noncontrolling interests		—			—			1,348			—			1,348
Other financing activities		(494		)	1,413			462			(213		)	1,168
Intercompany advances, net		1,533			(1,751		)	218			—			—
Net Cash Provided By (Used In) Financing Activities		1			(2,231		)	2,601			(213		)	158
Net increase in cash and cash equivalents		1			—			248			—			249
Cash and cash equivalents, beginning of		1			—			101			—			102
period
Cash and cash equivalents, end of period		$	2		$	—		$	349		$	—		$	351
___________________________________________
(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 $2 million which was incorrectly presented in the Guarantor Subsidiaries column. The impact of this error was not material to any previously issued financial statements.

Basis_of_Presentation_and_Summ3

Basis of Presentation and Summary of Significant Accounting Policies Significant Accounting Policies - Accounts Receivable Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'
Other receivables	$150	$168
Oil and gas joint interest billing receivables, current	417	592
Accounts Receivable, Related Parties	62	23
Allowance for Doubtful Accounts Receivable	-18	-19
Accounts receivable, net	2,222	2,245
Exploration and Production	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'
Other receivables	1,548	1,457
Oilfield Services	'	'
Accounts, Notes, Loans and Financing Receivable [Line Items]	'	'
Other receivables	$63	$24

Basis_of_Presentation_and_Summ4

Basis of Presentation and Summary of Significant Accounting Policies Significant Accounting Policies - Costs of Unproved Properties Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract]	'	'	'	'
Acquisition Costs, Cumulative	$9,056	'	'	'
Exploration Costs, Cumulative	1,065	'	'	'
Capitalized Interest Of Unproved Properties Excluded From Amortization Cumulative	1,892	'	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative	12,013	14,755	'	'
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost [Abstract]	'	'	'	'
Acquisition Costs, Period Cost	229	1,648	2,113	5,066
Exploration Costs, Period Cost	623	341	93	8
Capitalized Interest of Unproved Properties Excluded from Amortization	667	516	270	439
Capitalized Costs of Unproved Properties Excluded from Amortization, Period Cost	$1,519	$2,505	$2,476	$5,513

Basis_of_Presentation_and_Summ5

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Summary of Significant Accounting Policies [Line Items]	'	'	'
Equity Method Investment, Ownership Percentage	50.00%	'	'
Provision for Doubtful Accounts	$2,000,000	$0	$1,000,000
Goodwill	'	43,000,000	'
Bank Overdrafts	397,000,000	432,000,000	'
Unamortized Debt Issuance Expense	145,000,000	182,000,000	'
Gas Balancing Asset (Liability)	11,000,000	9,000,000	'
Premiums Receivable, Allowance for Doubtful Accounts, Write Offs Against Allowance	3,000,000	'	'
Natural Gas [Member]	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Percentage Of PortFolio	81.00%	'	'
Bronco Drilling Company Incorporated [Member]	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Goodwill	28,000,000	'	'
Horizon Drilling Services [Member]	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Goodwill	$15,000,000	'	'
Employee [Member] | Minimum	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years	'	'
Employee [Member] | Maximum	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'4 years	'	'
Director [Member]	'	'	'
Summary of Significant Accounting Policies [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	'3 years	'	'

Earnings_Per_Share_Antidilutiv

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Basic	$0.73	($1.46)	$2.47
Diluted	$0.73	($1.46)	$2.32
Basic	653	643	637
Weighted Average Number of Shares Outstanding, Diluted	653	643	752
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Net Income Adjustments	$86	$86	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	56	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	63	63	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	40	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	10	10	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	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	12	12	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	'
Restricted stock	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'
Net Income Adjustments	$10	$0	'
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	5	'

Earnings_Per_Share_Earnings_Pe

Earnings Per Share Earnings Per Share - Reconciliation of Basic and Diluted EPS Table (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share Disclosure [Line Items]	'	'	'
Net Income (Loss) Available to Common Stockholders, Basic	$474	($940)	$1,570
Basic	653	643	637
Basic	$0.73	($1.46)	$2.47
Diluted	$0.73	($1.46)	$2.32
Net Income (Loss) Attributable to Parent	724	-769	1,742
Weighted Average Number of Shares Outstanding, Diluted	653	643	752
Restricted stock	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	9
Amount of Dilutive Securities, Restrictive Stock Units	'	'	0
Stock Options	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	1
Amount of Dilutive Securities, Stock Options	'	'	0
5.75% Cumulative Convertible Preferred Stock	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Effect Of Dilutive Securities On Net Income Loss	'	'	86
5.75% Cumulative Convertible Preferred Stock | Convertible Debt Securities [Member]	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	55
5.75% Cumulative Convertible Preferred Stock Series A | Convertible Debt Securities [Member]	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Effect Of Dilutive Securities On Net Income Loss	'	'	63
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	39
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member] | Convertible Debt Securities [Member]	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Effect Of Dilutive Securities On Net Income Loss	'	'	11
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	5
4.50% Cumulative Convertible Preferred Stock [Member] | Convertible Debt Securities [Member]	'	'	'
Earnings Per Share Disclosure [Line Items]	'	'	'
Effect Of Dilutive Securities On Net Income Loss	'	'	$12
Weighted Average Number Diluted Shares Outstanding Adjustment	'	'	6

Debt_LongTerm_Debt_Table_Detai

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

12 Months Ended

12 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

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

7.625% Senior Notes Due 2013

6.625% Senior Notes Due 2019

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]

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

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Note Discounts [Member]

Note Discounts [Member]

Senior Secured Term Loan Due 2017

Senior Secured Term Loan Due 2017

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

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

6.25% 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

6.775% Senior Notes Due 2019

6.775% 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 [Member]

5.375% Senior Notes due 2021 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

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

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Long-Term Debt Instrument [Line Items]

'

'

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'

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'

'

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Long-term Debt, Gross

$12,886

$12,620

$0

$0

$405

$418

$13

$20

'

'

'

'

'

'

$2,000

$2,000

$2,300

'

$0

$464

$1,265

$1,265

$500

$0

$473

$454

$473

'

'

$660

$660

$97

$474

$669

$669

$650

$650

$0

$1,300

$1,300

$1,300

$500

$500

$1,000

$1,000

$700

$0

$1,100

$0

$396

$396

$1,168

$1,168

$347

$347

'

'

Current maturities of long-term debt, net

0

-463

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Long-term Debt, Excluding Current Maturities

12,886

12,157

'

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Debt Instrument, Unamortized Discount

'

'

'

'

'

'

'

'

'

'

'

'

'

$114

$33

$40

$303

$376

$1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

($357)

($465)

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3743

1.3193

1.3325

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

7.63%

6.63%

'

'

'

'

'

'

'

'

7.63%

'

9.50%

'

3.25%

'

'

'

6.25%

'

6.25%

6.50%

'

6.88%

'

7.25%

'

6.63%

'

6.78%

'

6.63%

'

6.88%

'

6.13%

'

5.38%

'

5.75%

'

2.75%

'

2.50%

'

2.25%

'

'

'

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

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Convertible, Terms of Conversion Feature

'5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock Price Conversion Thresholds

'

'

'

'

'

'

'

'

'

'

$48.09

$63.62

$106.75

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Date of First Required Payment

'

'

'

'

'

'

'

'

'

'

14-May-16

14-Nov-17

14-Jun-19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Long_Term_Debt_Table_Phan

Debt - Long Term Debt Table (Phantom) (Details)

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Senior Secured Term Loan Due 2017

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

9.5% Senior Notes Due 2015

3.25% Senior Notes due 2016

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.5% Senior Notes Due 2017

6.875% Senior Notes Due 2018

7.25% Senior Notes Due 2018

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

6.775% Senior Notes Due 2019

6.625% Senior Notes Due 2020

6.875% Senior Notes Due 2020

5.375% Senior Notes due 2021 [Member]

6.125% Senior Notes Due 2021

5.75% Senior Notes due 2023 [Member]

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

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

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

7.63%

7.63%

9.50%

3.25%

6.25%

6.25%

6.50%

6.88%

7.25%

6.63%

6.63%

6.78%

6.63%

6.88%

5.38%

6.13%

5.75%

'

2.75%

'

2.50%

'

2.25%

Debt Instrument Maturity Year

'2017

'

'2013

'2015

'2016

'2017

'

'2017

'2018

'2018

'

'2019

'2019

'2020

'2020

'2021

'2021

'2023

'

'2035

'

'2037

'

'2038

Debt Instruments Convertible Optional Repurchase Dates

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'November 15, 2015, 2020, 2025, 2030

'

'May 15, 2017, 2022, 2027, 2032

'

'December 15, 2018, 2023, 2028, 2033

'

Debt_Debt_Schedule_of_Debt_Mat

Debt Debt - Schedule of Debt Maturities Table (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Schedule of Debt Maturities [Abstract]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$0
Long-term Debt, Maturities, Repayments of Principal in Year Two	1,661
Long-term Debt, Maturities, Repayments of Principal in Year Three	905
Long-term Debt, Maturities, Repayments of Principal in Year Four	4,301
Long-term Debt, Maturities, Repayments of Principal in Year Five	1,113
Long-term Debt, Maturities, Repayments of Principal after Year Five	5,250
Long-term Debt	$13,230

Debt_Term_Loans_Narrative_Deta

Debt - Term Loans Narrative (Details) (USD $)	12 Months Ended			3 Months Ended	12 Months Ended					12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Nov. 07, 2012	31-May-12	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
				Term Loan [Member]	Term Loan [Member]	Term Loan [Member]	Term Loan [Member]	Term Loan [Member]	Term Loan [Member]	Term Loan [Member]	Term Loan [Member]
									Euro Rate Floor Percentage Per Annum [Member]	Base Rate Floor Percentage Per Annum [Member]	Maximum
Long-Term Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Credit Facility Commitment Period	'	'	'	'five-year	'	'	'	'	'	'	'
Unsecured Debt	'	'	'	'	'	'	$2,000,000,000	$4,000,000,000	'	'	'
Net proceeds from issuance of unsecured loan	'	'	'	1,935,000,000	'	'	'	'	'	'	'
Debt Instrument, Interest Rate, Effective Percentage Rate Range, Minimim	'	'	'	'	3.50%	'	'	'	'	4.50%	'
Base Rate Margin	'	'	'	'	0.50%	'	'	'	'	'	'
Euro Rate Margin	'	'	'	'	1.00%	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	'	'	'	'	'	'	'	1.25%	2.25%	'
Long-term Debt, Gross	12,886,000,000	12,620,000,000	'	'	'	'	'	'	'	'	125,000,000
Losses on purchases of debt and extinguishment of other financing	40,000,000	200,000,000	5,000,000	'	'	200,000,000	'	'	'	'	'
Write off of Deferred Debt Issuance Cost	'	'	'	'	'	86,000,000	'	'	'	'	'
Debt Instrument, Unamortized Discount	'	'	'	$114,000,000	'	$114,000,000	'	'	'	'	'

Debt_Senior_Notes_and_Continge

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

12 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Senior Notes

Senior Notes

Term Loan [Member]

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

6.775% Senior Notes Due 2019

6.775% Senior Notes Due 2019

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

6.625% Senior Notes Due 2019

5.375% Senior Notes due 2021 [Member]

5.375% Senior Notes due 2021 [Member]

5.75% Senior Notes due 2023 [Member]

5.75% Senior Notes due 2023 [Member]

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

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

50.00%

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Outstanding Principal Amount

'

'

'

'

'

'

$50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

2.50%

'

2.75%

'

2.25%

'

3.25%

'

6.78%

'

7.63%

'

7.63%

'

6.63%

6.63%

'

'

5.38%

'

5.75%

'

6.88%

'

Debt Instrument, Interest Rate, Effective Percentage

'

'

'

'

'

'

'

'

8.00%

'

6.86%

'

8.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

2,274

1,263

1,614

2,274

'

'

'

'

'

'

'

'

'

'

'

'

'

1,263

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

12,886

12,620

'

2,300

'

'

'

50

1,168

1,168

396

396

347

347

500

0

0

1,300

'

'

0

464

'

650

650

'

700

0

1,100

0

97

474

Long-term Debt

13,230

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Write off of Deferred Debt Issuance Cost

'

'

'

5

'

86

'

'

'

'

'

'

'

'

'

'

19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Discount

'

'

'

303

376

114

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

Write-off of Debt Discount

'

'

'

32

'

'

'

'

'

'

'

'

'

'

'

'

14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Notes Payable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

247

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchase Amount

'

'

'

405

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

221

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

217

'

'

'

'

'

'

'

'

'

377

'

Gain (Loss) on Repurchase of Debt Instrument

'

'

'

$37

'

'

'

'

'

'

'

'

'

'

'

'

$33

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Principal Amount Redeemed Percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

Debt_Bank_Credit_Facilities_Ta

Debt - Bank Credit Facilities Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
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 December 31, 2013	0
Letters of credit outstanding as of December 31, 2013	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 December 31, 2013	405
Letters of credit outstanding as of December 31, 2013	$0

Debt_Bank_Credit_Facilities_Na

Debt - Bank Credit Facilities Narrative (Details) (USD $)	3 Months Ended				12 Months Ended
	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2013
Long-Term Debt Instrument [Line Items]	'	'	'	'	'
Long-term Debt	'	'	'	'	$13,230,000,000
Long-term Debt, Gross	'	'	12,620,000,000	'	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%
Increase to Applicable Margin, Credit Facility	'	'	'	'	0.25%
Credit Facility Borrowing Capacity Margin	'	'	'	'	50.00%
Minimum Collateral Value, Credit Facility	'	'	'	'	75,000,000
Debt Instrument, Covenant Description	'4.00 to 1.00	'4.75 to 1.00	'5.00 to 1.00	'6.00 to 1.00	'
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	'	'	418,000,000	'	405,000,000
Line of Credit Facility, Amount Outstanding	'	'	'	'	405,000,000
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%

Contingencies_Narrative_Detail

Contingencies - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Loss Contingency [Abstract]	'	'
Loss Contingency, Damages Paid, Value	$3,000,000	$600,000
Loss Contingency Term	'10 years	'

Contingencies_and_Commitments_2

Contingencies and Commitments Commitments - Undiscounted Future Lease Payments Table (Details) (USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Operating Leased Assets [Line Items]	'
Other Commitment, Due in Second Year	$72
Other Commitment, Due in Third Year	119
Other Commitment, Due in Fourth Year	33
Operating Leases, Future Minimum Payments, Due in Five Years	32
Operating Leases, Future Minimum Payments Due, Next Twelve Months	117
Other Commitment, Due after Fifth Year	2
Other Commitment	375
Drilling Rigs [Member]	'
Operating Leased Assets [Line Items]	'
Other Commitment, Due in Second Year	11
Other Commitment, Due in Third Year	6
Other Commitment, Due in Fourth Year	7
Operating Leases, Future Minimum Payments, Due in Five Years	1
Operating Leases, Future Minimum Payments Due, Next Twelve Months	51
Other Commitment, Due after Fifth Year	0
Other Commitment	76
Compressor [Member]	'
Operating Leased Assets [Line Items]	'
Other Commitment, Due in Second Year	50
Other Commitment, Due in Third Year	104
Other Commitment, Due in Fourth Year	23
Operating Leases, Future Minimum Payments, Due in Five Years	29
Operating Leases, Future Minimum Payments Due, Next Twelve Months	53
Other Commitment, Due after Fifth Year	1
Other Commitment	260
Property, Plant and Equipment, Other Types	'
Operating Leased Assets [Line Items]	'
Other Commitment, Due in Second Year	11
Other Commitment, Due in Third Year	9
Other Commitment, Due in Fourth Year	3
Operating Leases, Future Minimum Payments, Due in Five Years	2
Operating Leases, Future Minimum Payments Due, Next Twelve Months	13
Other Commitment, Due after Fifth Year	1
Other Commitment	$39

Commitments_Undiscounted_Gathe

Commitments - Undiscounted Gathering Processing and Transportation Agreements Commitments Table (Details) (Gas Gathering and Processing Equipment [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Gas Gathering and Processing Equipment [Member]	'
Other Commitments [Line Items]	'
Other Commitment, Due in Next Twelve Months	$2,002
Other Commitment, Due in Second Year	1,829
Other Commitment, Due in Third Year	1,921
Other Commitment, Due in Fourth Year	1,948
Other Commitment, Due in Fifth Year	1,762
Other Commitment, Due after Fifth Year	7,728
Other Commitment	$17,190

Contingencies_and_Commitments_3

Contingencies and Commitments Commitments - Undiscounted Future Driling Commitments Table (Details) (Drilling Obligations [Member], USD $)	Dec. 31, 2013
In Millions, unless otherwise specified
Drilling Obligations [Member]	'
Other Commitments [Line Items]	'
Other Commitment, Due in Next Twelve Months	$36
Other Commitment, Due in Second Year	5
Other Commitment	$41

Commitments_Narrative_Details

Commitments - Narrative (Details) (USD $)

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Apr. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Minimum

Maximum

Net Acreage Shortfall [Member]

Net Acreage Shortfall [Member]

Net Acreage Maintenance Commitment [Member]

Net Acreage Maintenance Commitment [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Equipment

Compressor [Member]

Leasehold Improvements [Member]

Compressor [Member]

Compressor [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Drilling Rigs [Member]

Oilfield Services and Other [Member]

Property, Plant and Equipment, Other Types

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Third Party [Member]

well

well

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

acre

Scenario, Forecast [Member]

Rigs

Year of 2013 [Member]

Minimum

Maximum

Rigs

Compressor

Equipment Leased [Member]

Equipment Leased [Member]

acre

Rigs

Compressor

Rigs

Long-term Purchase Commitment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equipment, Number of Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,781

'

'

45

'

'

'

'

'

'

Number Of Drilling Rigs Leased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of repurchased equipment

'

'

'

'

'

'

'

'

'

'

'

'

23

23

'

'

'

541

'

'

'

'

'

'

'

'

'

'

'

'

Lease Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'6 months

'3 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Commitment

'

$375

'

'

'

'

'

'

'

'

'

'

$142

'

'

'

'

$73

'

$260

'

$76

'

'

'

$39

'

'

'

'

Gain (Loss) on Contract Termination

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22

'

'

'

'

'

'

'

15

Payments to Acquire Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

'

141

'

'

'

'

97

'

'

'

141

'

'

'

'

'

'

'

'

Impairment of Long-Lived Assets to be Disposed of

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

22

'

'

27

26

'

'

'

22

6

43

'

Minimum committed wells per year

'

'

'

'

90

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum committed wells per year, year one

'

'

'

'

270

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum committed wells per year, year two

'

'

'

'

540

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of spud wells

'

'

'

'

'

423

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Drilling carrying percentage, previous amount

'

'

'

'

'

'

'

60.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Drilling carrying percentage, current amount

'

'

'

'

'

'

45.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Commitment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

30

'

17,190

'

'

'

Net Acreage Shortfall

'

'

'

'

'

'

'

'

13,000

14,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Asset Impairment Charges

'

87

'

'

'

'

'

'

'

'

2

26

'

'

'

'

'

'

'

'

'

'

'

'

'

16

26

'

'

'

Amount Payable On Each Short Of Drilling Commitment

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Guaranteed gross profit margin

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Operating Leases, Rent Expense

'

$158

$185

$184

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other_Liabilities_ShortTerm_Ta

Other Liabilities - Short-Term Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Liabilities, Current [Abstract]	'	'
Revenues and royalties due others	$1,409	$1,337
Accrued natural gas, oil and NGL drilling and production costs	457	525
Joint interest prepayments received	464	749
Accrued compensation and benefits	320	225
Other accrued taxes	161	130
Accrued dividends	101	101
Other	599	674
Total other current liabilities	$3,511	$3,741

Other_Liabilities_LongTerm_Tab

Other Liabilities - Long-Term Table (Details) (USD $)	12 Months Ended									12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2009	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2009	Dec. 31, 2009	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013
	Property			Minimum	Maximum	Chesapeake Utica L L C [Member]	Chesapeake Utica L L C [Member]	Chesapeake Cleveland Tonkawa L.L.C	Chesapeake Cleveland Tonkawa L.L.C	Barnett Lease [Member]
Other Long-Term Liabilities [Line Items]	'	'	'	'	'	'	'	'	'	'
Conveyance Obligation Noncurrent	'	'	'	'	'	$250	$275	$149	$164	'
Financing obligations	'	31	175	'	'	'	'	'	'	'
Mortgages payable	'	0	56	'	'	'	'	'	'	'
Other	'	554	506	'	'	'	'	'	'	'
Total other long-term liabilities	'	984	1,176	'	'	263	293	161	178	'
Other liabilities, current	'	3,511	3,741	'	'	13	18	12	14	'
Number Of Real Estate Assets Financed	111	'	'	'	'	'	'	'	'	'
Lease Termination Costs	'	'	'	'	'	'	'	'	'	258
Gain (Loss) on Contract Termination	'	'	'	'	'	'	'	'	'	123
Operating Leases, Income Statement, Minimum Lease Revenue	145	'	'	'	'	'	'	'	'	'
Lease Agreement Contractual Term	'40 years	'	'	'	'	'	'	'	'	'
Capital Leases, Future Minimum Payments Receivable	$54	'	'	$15	$27	'	'	'	'	'
Mortgage Term	'5 years	'	'	'	'	'	'	'	'	'
Debt Instrument, Basis Points	275	'	'	'	'	'	'	'	'	'

Income_Taxes_Income_Taxes_Inco

Income Taxes Income Taxes - Income Tax Expense Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 30, 2011	Dec. 31, 2011
Income Tax - Current and Deferred [Abstract]	'	'	'	'
Current Federal Tax Expense (Benefit)	$0	$0	'	$0
Current State and Local Tax Expense (Benefit)	22	47	'	13
Current income taxes	22	47	'	13
Deferred Federal Income Tax Expense (Benefit)	502	-358	1,044	'
Deferred State and Local Income Tax Expense (Benefit)	24	-69	66	'
Deferred income taxes	526	-427	1,110	1,110
Total Income Tax Expense (Benefit)	$548	($380)	'	$1,123

Income_Taxes_Income_Taxes_Effe

Income Taxes Income Taxes - Effective Income Tax Rate Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Income tax expense (benefit) at the federal statutory rate (35%)	$505	($341)	$1,008
State income taxes (net of federal income tax benefit)	38	-38	74
Effective Income Tax Rate Reconciliation, Other Adjustments, Amount	5	-1	41
Total Income Tax Expense (Benefit)	$548	($380)	$1,123

Income_Taxes_Income_Taxes_Defe

Income Taxes Income Taxes - Deferred Tax Assets and Liabilities Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Income Tax Disclosure [Abstract]	'	'
Deferred Tax Liabilities, Other Finite-Lived Assets	($2,631)	($1,999)
Deferred Tax Liabilities, Property, Plant and Equipment	-371	-436
Deferred Tax Liabilities, Deferred Expense, Other Capitalized Costs	-1,216	-1,432
Deferred Tax Liabilities, Deferred Expense, Deferred Financing Costs	-439	-416
Deferred Tax Liabilities, Gross	-4,657	-4,283
Deferred Tax Assets, Operating Loss Carryforwards	535	711
Deferred Tax Assets, Derivative Instruments	108	172
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Asset Retirement Obligations	153	142
Deferred Tax Assets, Investment in Subsidiaries	130	106
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	66	47
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals, Accrued Liabilities	120	90
Deferred Tax Assets, Noncontrolling Interests	152	178
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	317	225
Deferred Tax Assets, Other	40	55
Deferred Tax Assets, Gross	1,621	1,726
Deferred Tax Assets, Valuation Allowance	-148	-160
Deferred Tax Assets, Net of Valuation Allowance	1,473	1,566
Deferred Tax Assets, Net	-3,184	-2,717
Deferred income tax asset	223	90
Deferred Tax Liabilities, Net, Noncurrent	-3,407	-2,807
Deferred Tax Liabilities, Net	($3,184)	($2,717)

Income_Taxes_Income_Taxes_NOL_

Income Taxes Income Taxes - NOL Activity Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]	'
Operating Loss Carryforwards	$592
AMT net operating loss	650
Limited [Member]	'
Operating Loss Carryforwards [Line Items]	'
Operating Loss Carryforwards	49
AMT net operating loss	35
Annual Limitation [Member]	'
Operating Loss Carryforwards [Line Items]	'
Operating Loss Carryforwards	15
AMT net operating loss	$15

Income_Taxes_Income_Taxes_Unre

Income Taxes Income Taxes - Unrecognized Tax Benefits Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 30, 2013	Dec. 30, 2012	Dec. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Disclosure [Abstract]	'	'	'	'	'	'	'
Unrecognized Tax Benefits Beginning of Period	'	'	'	$644	$599	$369	$34
Unrecognized Tax Benefits, Increase Resulting from Current Period Tax Positions	15	134	135	'	'	'	'
Unrecognized Tax Benefits, Increase Resulting from Prior Period Tax Positions	30	96	200	'	'	'	'
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities	0	0	0	'	'	'	'
Unrecognized Tax Benefits End of Period	'	'	'	$644	$599	$369	$34

Income_Taxes_Income_Taxes_Narr

Income Taxes Income Taxes - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Examination [Line Items]	'	'	'	'
Deferred income tax asset	$223	$90	'	'
Deferred income tax liabilities	3,407	2,807	'	'
Deferred Tax Assets, Operating Loss Carryforwards, windfalls	24	'	'	'
Operating Loss Carryforwards	592	'	'	'
Operating Loss Carrying Forwards Alternative Minimum Tax Amt	51	'	'	'
AMT NOL Carryback	'	599	'	'
Deferred Tax Assets, Gross	1,621	1,726	'	'
Deferred Tax Assets, Valuation Allowance	148	160	'	'
Treasury Regulations Purchase of Stock	5.00%	'	'	'
Unrecognized Tax Benefits	644	599	369	34
Accrued liability for interest related to uncertain tax positions	13	6	'	'
Percentage Of Beneficial Interest Owned	50.00%	'	'	'
Federal Jurisdiction [Member]	'	'	'	'
Income Tax Examination [Line Items]	'	'	'	'
Operating Loss Carryforwards	592	'	'	'
State and Local Jurisdiction [Member]	'	'	'	'
Income Tax Examination [Line Items]	'	'	'	'
Deferred income tax asset	328	'	'	'
Operating Loss Carryforwards	7,000	'	'	'
Unrecognized Tax Benefits	4	1	'	'
Valuation Allowance Change [Member]	'	'	'	'
Income Tax Examination [Line Items]	'	'	'	'
Operating Loss Carryforwards, Valuation Allowance	$12	'	'	'

Related_Party_Transactions_Tab

Related Party Transactions Tables (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
Related Party Transaction, Purchases from Related Party	$0	'	$0
Accounts Receivable, Related Parties, Current	47	67	29
Related Party Transaction, Due from (to) Related Party	1	42	115
FTS International, Inc.	'	'	'
Related Party Transaction [Line Items]	'	'	'
Related Party Transaction, Purchases from Related Party	'	73	'
Payment For Transaction with Related Party	397	480	369
Twin Eagle Resource Management Llc [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Revenue from Related Parties	$666	$392	$171
Equity Method Investment, Ownership Percentage	30.00%	'	'

Related_Party_Related_Party_Na

Related Party Related Party - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]	'	'	'
CEO Payment to the Company	'	$12	'
Related Party Transaction, Due from (to) Related Party	1	42	115
Ceo Aubrey K Mcclendon [Member]	'	'	'
Related Party Transaction [Line Items]	'	'	'
Early Termination Period	'	'18 months	'
FWPP Term	'	'10 years	'
Maximum working interest percentage allowed	'	2.50%	'
Due from Officers or Stockholders	62	23	'
Vesting Period for Executive Incentive Agreement	'	'5 years	'
Payment for Incentive Fee	'	75	'
Incentive Fee Employment Tax Effects	'	1	'
Amount of Executive Incentive Applied Against Costs Attributable to Interests in Company Ventures	'	44	'
Related Party Transaction, Expenses from Transactions with Related Party	'	15	'
FTS International, Inc.	'	'	'
Related Party Transaction [Line Items]	'	'	'
Payment For Transaction with Related Party	$397	$480	$369

Equity_Common_Stock_Table_Deta

Equity - Common Stock Table (Details)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 30, 2013

Dec. 31, 2013

Dec. 30, 2012

Dec. 31, 2012

Dec. 30, 2011

Dec. 31, 2011

Restricted stock

Restricted stock

Restricted stock

Stock Options

Stock Options

Stock Options

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

Preferred Stock

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common Stock, Shares, Issued Beginning of Period

666,192,371

666,467,664

660,888,000

655,251,000

'

'

'

'

'

'

'

'

'

'

'

'

Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures

'

'

'

'

-599,000

5,038,000

4,961,000

'

'

'

'

'

'

'

'

'

Stock option exercises

'

'

'

'

'

'

'

323,000

542,000

565,000

'

'

'

'

'

'

Stock Issued During Period, Shares, Conversion of Convertible Securities

'

'

'

'

'

'

'

'

'

'

0

0

0

0

111,000

3,000

Common Stock, Shares, Issued End of Period

666,192,371

666,467,664

660,888,000

655,251,000

'

'

'

'

'

'

'

'

'

'

'

'

Equity_Equity_Preferred_Stock_

Equity Equity - Preferred Stock Conversion Terms Table (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
5.75% Cumulative Convertible Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.75%
5.75% Cumulative Convertible Preferred Stock | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Stock Issue Date	'May and June 2010
Preferred Stock, Liquidation Preference Per Share	$1,000
Conversion of Stock, Holders Conversion Right	'Any time
Preferred Stock Conversion Rate	37.19%
Conversion of Stock, Conversion Price	$26.89
Conversion of Stock, Company Conversion Right, Date	'May 17, 2015
Trigger Price For Time Period	$34.96
Debt Instrument, Interest Rate, Stated Percentage	5.75%
5.75% Cumulative Convertible Preferred Stock Series A | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Stock Issue Date	'May 2010
Preferred Stock, Liquidation Preference Per Share	$1,000
Conversion of Stock, Holders Conversion Right	'Any time
Preferred Stock Conversion Rate	35.93%
Conversion of Stock, Conversion Price	$27.83
Conversion of Stock, Company Conversion Right, Date	'May 17, 2015
Trigger Price For Time Period	36.1776
Debt Instrument, Interest Rate, Stated Percentage	5.75%
4.50% Cumulative Convertible Preferred Stock [Member]	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	4.50%
4.50% Cumulative Convertible Preferred Stock [Member] | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Stock Issue Date	'September 2005
Preferred Stock, Liquidation Preference Per Share	$100
Conversion of Stock, Holders Conversion Right	'Any time
Preferred Stock Conversion Rate	2.30%
Conversion of Stock, Conversion Price	$43.54
Conversion of Stock, Company Conversion Right, Date	'September 15, 2010
Trigger Price For Time Period	56.5988
Debt Instrument, Interest Rate, Stated Percentage	4.50%
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.00%
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member] | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Stock Issue Date	'November 2005
Preferred Stock, Liquidation Preference Per Share	$100
Conversion of Stock, Holders Conversion Right	'Any time
Preferred Stock Conversion Rate	2.60%
Conversion of Stock, Conversion Price	$38.48
Conversion of Stock, Company Conversion Right, Date	'November 15, 2010
Trigger Price For Time Period	$50.02
Debt Instrument, Interest Rate, Stated Percentage	5.00%
Minimum | 5.75% Cumulative Convertible Preferred Stock Series A | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Company Market Trigger	25,000
Minimum | 4.50% Cumulative Convertible Preferred Stock [Member] | Preferred Stock	'
Share-based Compensation, Shares Authorized under Stock Option Plans, Exercise Price Range [Line Items]	'
Conversion of Stock, Company Market Trigger	250,000

Equity_Convertible_Preferred_S

Equity - Convertible Preferred Stock Table (Details)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 30, 2013

Dec. 31, 2013

Dec. 30, 2012

Dec. 31, 2012

Dec. 30, 2011

Dec. 31, 2011

Dec. 30, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2010

5.75% Cumulative Convertible Preferred Stock

5.75% Cumulative Convertible Preferred Stock Series A

4.50% Cumulative Convertible Preferred Stock [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

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

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]

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]

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

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares outstanding as of January 1

7,251,515

7,251,515

1,497,000

1,100,000

2,559,000

2,096,000

'

'

'

'

'

'

'

1,500,000

1,497,000

'

1,100,000

1,100,000

1,100,000

'

2,559,000

2,559,000

2,559,000

'

2,096,000

2,096,000

2,096,000

Shares outstanding as of December 31

7,251,515

7,251,515

1,497,000

1,100,000

2,559,000

2,096,000

'

'

'

'

'

'

'

1,497,000

1,497,000

'

1,100,000

1,100,000

1,100,000

'

2,559,000

2,559,000

2,559,000

'

2,096,000

2,096,000

2,096,000

Stock Issued During Period, Shares, Conversion of Convertible Securities

'

'

'

'

'

'

0

0

0

0

-111,000

-3,000

-3,000

-3,000

'

0

'

'

'

0

'

'

'

0

'

'

'

Equity_Equity_AOCI_Changes_Net

Equity Equity - AOCI Changes Net of Tax Table (Details) (USD $)	12 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 30, 2013	Dec. 31, 2013	Dec. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 30, 2013	Dec. 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 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 Other Comprehensive Income (Loss) [Line Items]	'	'	'	'	'	'	'	'	'	'	'
AOCI (Loss), Net of Tax - Period Start	($182)	'	'	'	($182)	'	($167)	($189)	'	$5	$7
Other comprehensive income before reclassifications	'	'	'	-4	'	2	'	'	-6	'	'
Amounts reclassified from accumulated other comprehensive income	'	'	'	24	24	20	'	'	4	'	'
Net current period other comprehensive income	20	-16	2	20	'	22	'	'	-2	'	'
AOCI (Loss), Net of Tax - Period End	($162)	($182)	'	'	($162)	'	($167)	($189)	'	$5	$7

Equity_Equity_AOCI_Reclassific

Equity Equity - AOCI Reclassifications Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 30, 2013	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$24	$24
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	'	20
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	'	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	'	($2)

Equity_Equity_Narrative_Detail

Equity Equity - Narrative (Details)	12 Months Ended
	Dec. 30, 2013	Dec. 31, 2013	Dec. 30, 2012	Dec. 31, 2012	Dec. 30, 2011	Dec. 31, 2011
4.50% Cumulative Convertible Preferred Stock [Member]	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	4.50%	'	'	'	'
5.75% Cumulative Convertible Preferred Stock	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	5.75%	'	'	'	'
5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	5.00%	'	'	'	'
Preferred Stock	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	0	0	0	0	111,000	3,000
Preferred Stock | 4.50% Cumulative Convertible Preferred Stock [Member]	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	4.50%	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	'	'	'	'	0	'
Preferred Stock | 5.75% Cumulative Convertible Preferred Stock	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	5.75%	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	'	'	'	'	3,000	3,000
Preferred Stock | 5.0% Cumulative Convertible Preferred Stock Series Two Thousand And Five B [Member]	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	5.00%	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	'	'	'	'	0	'
Paid-In Capital	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	'	0	'	0	'	111,111
Paid-In Capital | 5.75% Cumulative Convertible Preferred Stock	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Stock Issued During Period, Shares, Conversion of Convertible Securities	'	'	'	'	'	111,111

Equity_Noncontrolling_Interest

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

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

1 Months Ended

2 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Mar. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Nov. 30, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Nov. 30, 2011

Oct. 31, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

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 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]

acre

well

well

Minimum

Maximum

Drilled Wells

Future [Member]

Future [Member]

Increase

Preferred Stock

well

well

Minimum

Maximum

Maximum

Initial Wells [Member]

Subordinated Units

Common Unit

Common Unit

acre

well

well

well

County

Minimum

Drilled Wells

Drilled Wells

Preferred Dividend Payments [Member]

Preferred Dividend Payments [Member]

Divestiture Payments [Member]

Preferred Stock

acre

well

well

Minimum

well

well

Minimum

acre

well

acre

well

well

well

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

'

'

'

'

'

75

85

'

'

'

'

1,000

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

1,500

1,500

'

1,500

1,300

'

'

'

'

'

'

'

'

Restricted cash and cash equivalents, current

75,000,000

111,000,000

'

'

'

38,000,000

57,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

44,000,000

'

'

'

'

Restricted Cash and Cash Equivalents, Noncurrent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

155,000,000

'

'

'

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)

'

'

'

'

'

$1,245

$1,305

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,252

$1,322

'

'

'

'

'

'

'

'

'

'

Number of oil wells committed to drill net, minimum

'

'

'

'

'

25

'

'

37.5

'

867

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

'

Number Of Net Wells Minimum Cumulative Total

'

'

'

'

'

'

'

'

'

300

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

250

'

'

'

'

'

'

'

'

'

'

'

ORRI Wells Delivered in Period

'

'

'

'

'

84

77

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

149

28

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

82

55

'

'

'

'

118

'

'

'

'

'

'

'

'

'

111

61

'

'

'

'

'

'

Number of counties present in the leasehold land (Counties)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13

'

'

'

'

'

'

'

'

'

Amount Payable On Each Short Of Drilling Commitment

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

666,192,371

666,467,664

660,888,000

655,251,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

79,000,000

140,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51.00%

'

Payments of Ordinary Dividends, Preferred Stock and Preference Stock

171,000,000

171,000,000

172,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

212,000,000

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, par value (usd per share)

$0.01

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,115

'

'

'

'

'

'

'

'

'

'

'

Percentage of Preferred Shares Repurchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

Premium on purchase of preferred shares of a subsidiary

69,000,000

0

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69,000,000

'

'

'

'

'

'

'

'

'

'

'

Stock Redeemed or Called During Period, Shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

190,000

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interests

2,145,000,000

2,327,000,000

'

'

'

1,015,000,000

1,015,000,000

'

'

'

'

'

'

'

'

314,000,000

356,000,000

'

'

'

'

'

'

'

'

'

'

807,000,000

950,000,000

'

'

'

'

'

'

'

'

9,000,000

5,000,000

Net Income (Loss) Attributable to Noncontrolling Interest

$170,000,000

$175,000,000

$15,000,000

'

'

$75,000,000

$57,000,000

'

'

'

'

'

'

'

'

$20,000,000

$35,000,000

'

'

'

'

'

'

'

'

'

'

$79,000,000

$88,000,000

'

'

'

'

'

'

'

'

$4,000,000

$4,000,000

Equity_Noncontrolling_Interest1

Equity - Noncontrolling Interests Distribution Table (Details) (Chesapeake Granite Wash Trust, USD $)	3 Months Ended
	Aug. 31, 2013	31-May-13	Feb. 28, 2013	Nov. 30, 2012	Aug. 31, 2012	31-May-12	Feb. 29, 2012	Nov. 30, 2011
Noncontrolling Interest [Line Items]	'	'	'	'	'	'	'	'
Distribution Made to Limited Partner, Distribution Date	29-Nov-13	29-Aug-13	31-May-13	1-Mar-13	29-Nov-12	30-Aug-12	31-May-12	1-Mar-12
Common Unit	'	'	'	'	'	'	'	'
Noncontrolling Interest [Line Items]	'	'	'	'	'	'	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0.6671	0.69	0.69	0.67	0.63	0.61	0.6588	0.7277
Subordinated Units	'	'	'	'	'	'	'	'
Noncontrolling Interest [Line Items]	'	'	'	'	'	'	'	'
Distribution Made to Limited Partner, Cash Distributions Declared, Per Unit	0	0.1432	0.301	0.3772	0.2208	0.4819	0.6588	0.7277

ShareBased_Compensation_ShareB

Share-Based Compensation Share-Based Compensation - Restricted Stock Table (Details) (Restricted stock, USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 30, 2013	Dec. 30, 2012	Dec. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
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	'	'	'	13,400	18,899	19,544	21,375
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	9,189	9,480	9,541	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	-12,897	-8,620	-10,401	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	-1,791	-1,505	-971	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Shares, Period End	'	'	'	13,400	18,899	19,544	21,375
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period Start	'	'	'	$23.38	$23.72	$26.97	$28.68
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$19.68	$21.13	$28.38	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$21.32	$28.08	$31.76	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Forfeitures and Expirations in Period, Weighted Average Exercise Price	$22.86	$24.57	$27.28	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value, Period End	'	'	'	$23.38	$23.72	$26.97	$28.68

ShareBased_Compensation_ShareB1

Share-Based Compensation Share-Based Compensation - Stock Option Valuation Table (Details)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions and Methodology [Abstract]	'
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	'6 years 5 months 25 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	48.47%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.30%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	1.82%

ShareBased_Compensation_ShareB2

Share-Based Compensation Share-Based Compensation - Stock Option Activity Table (Details) (USD $)	0 Months Ended		12 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Dec. 30, 2013	Dec. 30, 2012	Dec. 30, 2013	Dec. 30, 2012	Dec. 30, 2011	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2013	Dec. 31, 2012
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	'	'	'	'	'	1,808	'	5,268	481
Stock Options Granted	'	'	5,264	'	'	'	'	'	'
Stock Options Exercised	'	'	-346	-570	-757	'	'	'	'
Stock Options Expired	'	'	-131	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Number Period End	'	'	'	'	'	1,051	1,808	5,268	481
Exercisable, end of period	'	'	'	'	'	'	'	1,552	'
Weighted Average Exercise Price [Roll Forward]	'	'	'	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period Start	'	'	'	'	'	$8.90	'	$19.28	$12.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value	'	'	$19.32	'	'	'	'	'	'
Share-based Compensation Arrangements by Share-based Payment Award, Options, Exercises in Period, Weighted Average Exercise Price	'	'	$10.82	$7.45	$7.59	'	'	'	'
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price	'	'	$19.31	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Exercise Price Period End	'	'	'	'	'	$9.84	$8.90	$19.28	$12.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	'	'	'	'	'	'	'	$18.82	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period Start	'	'	'	'	'	$31	'	$41	$2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Intrinsic Value	'	'	11	7	15	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value Period End	'	'	'	'	'	13	31	41	2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	'	'	'	'	'	'	'	$13	'
Weighted Average Contract Life (in years) [Roll Forward]	'	'	'	'	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	'6 years 7 months 27 days	'350 days	'	'	'	'514 days	'741 days	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'1 year 11 months 18 days	'	'	'	'	'	'	'	'

ShareBased_Compensation_ShareB3

Share-Based Compensation Share-Based Compensation - Share-Based Compensation Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$48	$14	$0
Stock Compensation Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share Based Compensation Natural Gas and Oil Properties	52	71	112
Share Based Compensation General And Administrative Expense	60	71	92
Share Based Compensation Natural Gas And Oil Production Expenses	21	24	33
Share Based Compensation Allocated To Marketing Gathering And Compression Expense	7	15	17
Share Based Compensation Service Operations Expense	10	10	11
Allocated Share-based Compensation Expense	$150	$191	$265

ShareBased_Compensation_ShareB4

Share-Based Compensation Share-Based Compensation - Performance Shares Table (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$48	$14	$0
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Performance Shares [Member] | Payable 2013 [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	2	'	'
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,112,331	'	'
Fair Value of Share Based Award	42	31	'
Share Based Award Liability, Current	41	'	'
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Payable 2014 [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	278,083	'	'
Fair Value of Share Based Award	11	8	'
Share Based Award Liability, Current	11	'	'
Long-Term Incentive Plan [Member] | Year of 2012 [Member] | Management [Member] | Performance Shares [Member] | Payable 2015 [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	834,248	'	'
Fair Value of Share Based Award	31	23	'
Share Based Award Liability, Current	30	'	'
Long-Term Incentive Plan [Member] | Year of 2013 [Member] | Management [Member] | Performance Shares [Member] | Payable 2016 [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	1,600,438	'	'
Fair Value of Share Based Award	58	35	'
Share Based Award Liability, Current	$49	'	'

ShareBased_Compensation_ShareB5

Share-Based Compensation Share-Based Compensation - Performance Share Unit Breakout (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Allocated Share-based Compensation Expense	$48	$14	$0
Performance Shares [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Share Based Compensation Natural Gas and Oil Properties	9	4	0
Share Based Compensation General And Administrative Expense	34	8	0
Share Based Compensation Natural Gas And Oil Production Expenses	2	1	0
Share Based Compensation Allocated To Marketing Gathering And Compression Expense	2	1	0
Share Based Compensation Service Operations Expense	$1	$0	$0

ShareBased_Compensation_ShareB6

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

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

In Millions, except Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 31, 2013

Dec. 30, 2012

Dec. 31, 2012

Dec. 30, 2011

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2005

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Restricted stock

Restricted stock

Restricted stock

Restricted stock

Restricted stock

Restricted stock

Restricted stock

Stock Options

Stock Options

Stock Options

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Employee [Member]

Employee [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]

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]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

2003 Stock Incentive Plan [Member]

TSR is less than zero [Member]

Stock Option Award Three Year Anniversary [Member]

Stock Optioin Award Four Year Anniversary [Member]

Stock option Award Five Year Anniversary [Member]

Minimum

Retention Based Stock Option Award [Member]

Incentive Based Stock Option Award [Member]

Stock Options

Performance Shares [Member]

Prior to 2006 [Member]

Minimum

Maximum

Maximum

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Non-Employee Director [Member]

Non-Employee Director [Member]

Non-Employee Director [Member]

Employee [Member]

Employee [Member]

Employee [Member]

Maximum

Non-Employee Director [Member]

Non-Employee Director [Member]

Non-Employee Director [Member]

Non-Employee Director [Member]

Long-Term Incentive Plan [Member]

Management [Member]

Management [Member]

Management [Member]

Stock Options

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]

Maximum

Year of 2012 [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [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]

Minimum

Maximum

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

'

'3 years

'4 years

'3 years

'4 years

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3 years

'4 years

'5 years

Common Stock, Shares, Issued

666,192,371

666,467,664

660,888,000

655,251,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,000

'

'

'

'

'

'

'

Common Stock, Shares Authorized

1,000,000,000

1,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

59,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

10,000,000

'

'

'

250,000

'

'

'

'

Stock Issued During Period, Shares, Restricted Stock Award, Net of Forfeitures

'

'

'

'

-599,000

'

5,038,000

'

4,961,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

147,108

170,151

68,824

2,500,000

5,000,000

4,500,000

0

0

400,000

'

20,000

30,000

10,000

'

'

'

'

'

Remaining Shares Available For Issuance

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

12,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

130,000

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

$342

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'3 years 7 months

'

'

'

'

'

'2 years 6 months 5 days

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

195

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recognized Reduction In Tax Benefits

'

'

'

'

'

14

'

32

'

23

'

1

2

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33.00%

'

'

'

'

'

'

'

'

250.00%

0.00%

125.00%

200.00%

0.00%

125.00%

0.00%

62.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

'

'

'

Allocated Share-based Compensation Expense

$48

$14

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Employee_Benefit_Plans_Employe

Employee Benefit Plans Employee Benefit Plans - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Percentage of Employer Contribution	15.00%	'	'
Defined Benefit Plan, Contributions by Employer	$81,000,000	$91,000,000	$72,000,000
Minimum	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Minimum Annual Compensation Received	150,000	'	'
Performance Bonus [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Percentage Of Performance Bonus, Maximum Compensation Deferred	100.00%	'	'
Director Compensation [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Percentage of Basic Salary, Maximum Compensation Deferred	100.00%	'	'
Chesapeake Appalachia, L.L.C. [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Pension and Other Postretirement Defined Benefit Plans, Liabilities	3,000,000	'	'
Dc Plan [Member]	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	15.00%	'	'
Participant Age to Diversify Match	55	'	'
Deferred Compensation Arrangement with Individual, Employer Contribution	$14,000,000	$16,000,000	$12,000,000
Dc Plan [Member] | Maximum	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	100.00%	'	'
Percentage of Basic Salary, Maximum Compensation Deferred	75.00%	'	'

Derivative_and_Hedging_Activit2

Derivative and Hedging Activities - Derivative Instruments Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Fair Value	($551)	($924)
Natural Gas [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	1,009,000,000,000,000	353,000,000,000,000
Fair Value	-237	-231
Natural Gas [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	448,000,000,000,000	49,000,000,000,000
Fair Value	-23	24
Natural Gas [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	193,000,000,000,000	193,000,000,000,000
Fair Value	-210	-240
Natural Gas [Member] | Swaptions	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	12,000,000,000,000	0
Fair Value	0	0
Natural Gas [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	68,000,000,000,000	111,000,000,000,000
Fair Value	3	-15
Natural Gas [Member] | Three Way Collar [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	288,000,000,000,000	0
Fair Value	-7	0
Crude Oil [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	68,200,000	112,700,000
Fair Value	-314	-693
Crude Oil [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	25,300,000	28,100,000
Fair Value	-50	68
Crude Oil [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	42,500,000	73,800,000
Fair Value	-265	-748
Crude Oil [Member] | Swaptions	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	0	5,300,000
Fair Value	0	-13
Crude Oil [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	400,000	5,500,000
Fair Value	$1	$0

Derivative_and_Hedging_Activit3

Derivative and Hedging Activities - Natural Gas and Oil Sales Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General Discussion of Derivative Instruments and Hedging Activities [Abstract]	'	'	'
Natural gas, oil and NGL sales	$6,923	$5,359	$5,259
Gains on natural gas, oil and NGL derivatives	129	919	772
Gain (Loss) on Price Risk Cash Flow Hedge Ineffectiveness	0	0	-7
Total natural gas, oil and NGL sales	$7,052	$6,278	$6,024

Derivative_and_Hedging_Activit4

Derivative and Hedging Activities - Interest Rate Derivatives Table (Details) (Swap, USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Swap	'	'
Derivative [Line Items]	'	'
Notional Amount	$2,250	$1,050
Fair Value	($98)	($35)

Derivative_and_Hedging_Activit5

Derivative and Hedging Activities - Interest Income and Interest Expense Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Interest Income (Expense), Net [Abstract]	'	'	'
Interest expense on senior notes	$740	$732	$653
Interest expense on credit facilities	38	70	70
Interest expense on term loans	116	173	0
(Gains) losses on interest rate derivatives	58	-7	14
Amortization of loan discount, issuance costs and other	91	89	39
Capitalized interest	-816	-980	-732
Interest expense	$227	$77	$44

Derivative_and_Hedging_Activit6

Derivative and Hedging Activities - Derivative Instruments in Balance Sheet Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Asset Derivatives:	'	'
Short-term derivative assets	$0	$58
Liability Derivatives:	'	'
Total derivative instruments	-649	-979
Commodity contracts | Short [Member]	'	'
Asset Derivatives:	'	'
Short-term derivative assets	'	58
Asset commodity contracts	29	110
Liability Derivatives:	'	'
Liability commodity contracts	231	157
Commodity contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	11	5
Liability Derivatives:	'	'
Liability commodity contracts	362	882
Foreign currency contracts | Short [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Liability Derivatives:	'	'
Liability commodity contracts	0	0
Foreign currency contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	2	0
Liability Derivatives:	'	'
Liability commodity contracts	0	20
Interest rate contract | Short [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Liability Derivatives:	'	'
Liability commodity contracts	6	0
Interest rate contract | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Liability Derivatives:	'	'
Liability commodity contracts	92	35
Designated as Hedging Instrument	'	'
Asset Derivatives:	'	'
Short-term derivative assets	2	0
Liability Derivatives:	'	'
Liability commodity contracts	0	-20
Designated as Hedging Instrument | Foreign currency contracts	'	'
Asset Derivatives:	'	'
Short-term derivative assets	2	0
Liability Derivatives:	'	'
Liability commodity contracts	'	-20
Designated as Hedging Instrument | Foreign currency contracts | Long [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	0	'
Not designated as hedging instruments	'	'
Asset Derivatives:	'	'
Asset commodity contracts	40	115
Liability Derivatives:	'	'
Liability commodity contracts	-691	-1,074
Not designated as hedging instruments | Commodity contracts | Short [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	29	110
Liability Derivatives:	'	'
Liability commodity contracts	-231	-157
Not designated as hedging instruments | Commodity contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	11	5
Liability Derivatives:	'	'
Liability commodity contracts	-362	-882
Not designated as hedging instruments | Interest rate contract | Short [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	-6	0
Not designated as hedging instruments | Interest rate contract | Long [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	($92)	($35)

Derivative_and_Hedging_Activit7

Derivative and Hedging Activities - Netting Offsets Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Short-term derivative assets	$0	$58
Long-term derivative assets	4	2
Short-term derivative liabilities	-208	-105
Long-term derivative liabilities	-445	-934
Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset	40	115
Derivative Liability	593	1,039
Short [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Short-term derivative liabilities	208	'
Short [Member] | Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	29	110
Derivative Asset, Fair Value, Amount Offset Against Collateral	-29	-52
Derivative Asset	0	58
Liability commodity contracts	-231	-157
Derivative Liability, Fair Value, Amount Offset Against Collateral	29	52
Derivative Liability	-202	-105
Short-term derivative assets	'	58
Short-term derivative liabilities	'	105
Short [Member] | Interest rate contract	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	0
Derivative Asset	0	0
Liability commodity contracts	-6	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Liability	-6	0
Short [Member] | Foreign currency contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	0
Derivative Asset	0	0
Liability commodity contracts	0	0
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Liability	0	0
Long [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term derivative assets	4	'
Long [Member] | Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	11	5
Derivative Asset, Fair Value, Amount Offset Against Collateral	-9	-3
Derivative Asset	2	2
Liability commodity contracts	-362	-882
Derivative Liability, Fair Value, Amount Offset Against Collateral	9	3
Derivative Liability	-353	-879
Long-term derivative assets	'	2
Long-term derivative liabilities	'	934
Long [Member] | Interest rate contract	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	0	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	0
Derivative Asset	0	0
Liability commodity contracts	-92	-35
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Liability	-92	-35
Long [Member] | Foreign currency contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Asset commodity contracts	2	0
Derivative Asset, Fair Value, Amount Offset Against Collateral	0	0
Derivative Asset	2	0
Liability commodity contracts	0	-20
Derivative Liability, Fair Value, Amount Offset Against Collateral	0	0
Derivative Liability	$0	($20)

Derivative_and_Hedging_Activit8

Derivative and Hedging Activities - Derivative Instruments, Gain/Loss In Statement Of Financial Performance Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Interest rate contracts	($58)	$7	($14)
Fair Value Hedging | Interest rate contract | Interest Expense	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Interest rate contracts	$5	$8	$16

Derivative_and_Hedging_Activit9

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

Dec. 31, 2013

Dec. 31, 2012

Dec. 30, 2013

Dec. 31, 2013

Dec. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 30, 2013

Dec. 30, 2012

Dec. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

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]

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 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 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]

Balance Before Tax

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

Balance After Tax

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AOCI (Loss), Net of Tax - Period Start

($162)

($182)

'

($182)

'

($167)

($189)

'

'

'

($269)

($304)

($287)

($291)

'

'

'

($167)

($189)

($178)

($181)

Other Comprehensive Income Before Reclassifications, Net of Tax

'

'

'

'

'

'

'

3

10

368

'

'

'

'

2

6

228

'

'

'

'

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

'

'

24

24

20

'

'

32

-27

-364

'

'

'

'

20

-17

-225

'

'

'

'

AOCI (Loss), Net of Tax - Period End

($162)

($182)

'

($162)

'

($167)

($189)

'

'

'

($269)

($304)

($287)

($291)

'

'

'

($167)

($189)

($178)

($181)

Recovered_Sheet2

Derivative and Hedging Activities - Cash Flow Hedge Instruments Gain Loss in Statement of Financial Performance Table (Details) (Cash Flow Hedging [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	($32)	$27	$364
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	15
Sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	22
Sales [Member] | Ineffective Portion [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain (Loss) Recognized in Income, Ineffective Portion and Amount Excluded from Effectiveness Testing, Net	0	0	-7
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	3	10	368
Commodity contracts | Sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	-32	27	402
Commodity contracts | Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	0	0	392
Foreign currency contracts	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	'	10	'
Foreign currency contracts | Interest Expense	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	0	0	-18
Foreign currency contracts | Loss on Reacquired Debt [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	0	0	-20
Foreign currency contracts | Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Derivative Instruments, Gain Recognized in Other Comprehensive Income (Loss), Effective Portion	$3	'	($24)

Recovered_Sheet3

Derivative and Hedging Activities - Derivatives Not Designated as Hedging Instruments Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in net income (loss)	($58)	$7	($14)
Not designated as hedging instruments	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in net income (loss)	96	891	336
Not designated as hedging instruments | Commodity contracts | Sales [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in net income (loss)	159	892	348
Not designated as hedging instruments | Interest rate contract | Interest Expense	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Gain (loss) recognized in net income (loss)	($63)	($1)	($12)

Recovered_Sheet4

Derivative and Hedging Activities - Narrative (Details)

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2006

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2013

USD ($)

USD ($)

Senior Notes

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Price Risk Derivative [Member]

Basis 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

6.25% Euro-Denominated Senior Notes Due 2017

USD ($)

USD ($)

Credit Risk

Energy Related Derivative [Member]

Semi-Annual Collateral Dates

Between Semi-Annual Collateral Dates

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

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]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

EUR (€)

USD ($)

USD ($)

USD ($)

EUR (€)

Maturity Payment [Member]

Maturity Payment [Member]

USD ($)

EUR (€)

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of counterparties in hedge facility

'

'

'

16

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)

'

'

'

'

'

'

'

'

221,000,000

12,000,000

'

'

'

'

'

'

'

'

'

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

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

600,000,000

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

6.25%

'

6.25%

6.25%

'

'

Debt Instrument, Increase (Decrease), Net

'

'

'

'

'

'

'

'

'

'

'

'

256,000,000

'

'

'

'

'

'

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%

'

'

'

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

1.3743

1.3193

1.3325

'

'

'

Liability commodity contracts

'

'

'

'

'

'

'

'

'

'

'

'

'

2,000,000

'

'

'

'

'

Euro-denominated debt in notes payable, adjusted value

12,886,000,000

12,620,000,000

2,300,000,000

'

'

'

'

'

'

'

473,000,000

454,000,000

'

473,000,000

'

'

'

'

'

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

159,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Flow Hedges, Accumulated OCI Balance

167,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected amount to be transferred of during the next 12 months

$23,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Number of Instruments Held

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_D2

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

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Feb. 28, 2011

Dec. 31, 2013

Nov. 30, 2010

Dec. 31, 2013

Jan. 31, 2010

Dec. 31, 2013

Nov. 30, 2008

Dec. 31, 2013

Sep. 30, 2008

Dec. 31, 2013

Jul. 31, 2008

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

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

$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

$731

'

$0

'

$596

'

$135

'

$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 $)

12 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

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 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 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)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Mcfe	Mcfe	Mcfe
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	170,900,000,000	202,200,000,000	199,900,000,000
Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	154,000,000,000	178,400,000,000	189,200,000,000
Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	864,300	1,580,800	1,161,500
NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,964,700	2,372,700	615,400
VPP 10 Anadarko Basin Granite Wash [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	25,800,000,000	32,800,000,000	0
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	13,500,000,000	18,100,000,000	0
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	547,000	727,000	0
VPP 10 Anadarko Basin Granite Wash [Member] | NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,509,000	1,729,100	0
VPP 9 Mid-Continent [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	21,000,000,000	23,700,000,000	22,500,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	17,000,000,000	18,400,000,000	17,300,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	213,200	249,300	250,500
VPP 9 Mid-Continent [Member] | NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	455,700	643,600	615,400
VPP 8 Barnett Shale [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	68,100,000,000	79,700,000,000	101,200,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	68,100,000,000	79,700,000,000	101,200,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0
VPP 8 Barnett Shale [Member] | NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0
VPP 7 Permian Basin [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	'	3,400,000,000	5,000,000,000
VPP 7 Permian Basin [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	'	400,000,000	400,000,000
VPP 7 Permian Basin [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	'	490,300	773,000
VPP 7 Permian Basin [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)	4,900,000,000	5,500,000,000	6,200,000,000
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)	4,800,000,000	5,300,000,000	6,000,000,000
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)	24,000	24,000	27,000
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	0
VPP 5 South Texas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	7,700,000,000	9,000,000,000	11,200,000,000
VPP 5 South Texas [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	7,500,000,000	8,800,000,000	11,000,000,000
VPP 5 South Texas [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	25,400	27,400	35,900
VPP 5 South Texas [Member] | NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	10,500,000,000	12,200,000,000	14,300,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	10,200,000,000	11,700,000,000	13,800,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	54,700	62,800	75,100
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	0
VPP 3 Anadarko Basin [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	8,100,000,000	9,300,000,000	10,700,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	8,100,000,000	9,300,000,000	10,700,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0
VPP 3 Anadarko Basin [Member] | NGL Reserves	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0
VPP 2 Texas, Oklahoma and Kansas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	10,300,000,000	11,300,000,000	12,500,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	10,300,000,000	11,400,000,000	12,500,000,000
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	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	0
VPP 1 Kentucky and West Virginia [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Reserves (Energy) (Duration)	14,500,000,000	15,300,000,000	16,300,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	14,500,000,000	15,300,000,000	16,300,000,000
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	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	0

Natural_Gas_and_Oil_Property_D5

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

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

31-May-11

Dec. 31, 2013

31-May-11

Dec. 31, 2013

31-May-11

Dec. 31, 2013

31-May-11

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Sep. 30, 2010

Dec. 31, 2013

Feb. 28, 2010

Dec. 31, 2013

Feb. 28, 2010

Dec. 31, 2013

Feb. 28, 2010

Dec. 31, 2013

Feb. 28, 2010

Dec. 31, 2013

Aug. 31, 2009

Dec. 31, 2013

Aug. 31, 2009

Dec. 31, 2013

Aug. 31, 2009

Dec. 31, 2013

Aug. 31, 2009

Dec. 31, 2013

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2008

Dec. 31, 2013

Dec. 31, 2008

Dec. 31, 2013

Aug. 31, 2008

Dec. 31, 2013

Aug. 31, 2008

Dec. 31, 2013

Aug. 31, 2008

Dec. 31, 2013

Aug. 31, 2008

Dec. 31, 2013

31-May-08

Dec. 31, 2013

31-May-08

Dec. 31, 2013

31-May-08

Dec. 31, 2013

31-May-08

Dec. 31, 2013

Dec. 31, 2007

Dec. 31, 2013

Dec. 31, 2007

Dec. 31, 2013

Dec. 31, 2007

Dec. 31, 2013

Dec. 31, 2007

Dec. 31, 2013

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

'

'

'

'

'

'

'

'

'98 months

'

'

'

'

'86 months

'

'

'

'

'

'

'

'20 months

'

'

'

'

'

'

'

'73 months

'

'

'

'

'

'

'

'37 months

'

'

'

'

'

'

'

'36 months

'

'

'

'

'

'

'

'67 months

'

'

'

'

'

'

'

'64 months

'

'

'

'

'

'

'

'108 months

'

'

'

'

'

'

Proved Developed Reserves (Volume)

'

'

1,216,000,000,000

452,900,000,000

5,700,000

3,100,000

14,000,000

8,300,000

'

48,600,000,000

1,700,000

6,000,000

'

'

138,000,000,000

88,700,000,000

1,700,000

1,000,000

4,800,000

2,300,000

'

'

390,000,000,000

96,500,000,000

0

0

0

0

'

'

44,000,000,000

21,400,000,000

300,000

200,000

0

0

'

'

67,000,000,000

16,900,000,000

200,000

100,000

0

0

'

'

95,000,000,000

24,300,000,000

500,000

100,000

0

0

'

'

93,000,000,000

31,100,000,000

0

0

0

0

'

'

94,000,000,000

20,000,000,000

0

0

0

0

'

'

208,000,000,000

105,400,000,000

0

0

0

0

Proved Developed Reserves (Energy)

1,334,000,000,000

521,300,000,000

'

'

'

'

'

'

94,800,000,000

'

'

'

177,000,000,000

108,900,000,000

'

'

'

'

'

'

390,000,000,000

96,500,000,000

'

'

'

'

'

'

46,000,000,000

22,300,000,000

'

'

'

'

'

'

68,000,000,000

17,200,000,000

'

'

'

'

'

'

98,000,000,000

25,100,000,000

'

'

'

'

'

'

93,000,000,000

31,100,000,000

'

'

'

'

'

'

94,000,000,000

20,000,000,000

'

'

'

'

'

'

208,000,000,000

105,400,000,000

'

'

'

'

'

'

Natural_Gas_and_Oil_Property_D6

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

12 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

1 Months Ended

3 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2010

Dec. 31, 2012

Mar. 31, 2011

Mar. 31, 2011

Mcfe

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Permian Basin [Member]

Chitwood Knox [Member]

XTO Energy Inc. [Member]

Utica [Member]

Payment at Closing [Member]

Payment at Closing [Member]

Payment at Closing [Member]

Cash Payment [Member]

Payment Remaining [Member]

Payment Remaining [Member]

Subsequent Payment [Member]

Subsequent Payment [Member]

Subsequent Payment [Member]

Payment Received, Additional [Member]

Amount allocated to midstream and other fixed assets [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

JV Marcellus, Barnett and Utica [Member]

JV Marcellus, Barnett and Utica [Member]

JV Marcellus, Barnett and Utica [Member]

Corporate VPP [Member]

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

VPP 7 Permian Basin [Member]

VPP 7 Permian Basin [Member]

Fayetteville Shale [Member]

Fayetteville Shale [Member]

acre

acre

acre

acre

acre

MKR Holdings LLC [Member]

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Permian Basin [Member]

Northern Eagle Ford Shale [Member]

Permian Basin [Member]

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Permian Basin [Member]

Permian Basin [Member]

Permian Basin [Member]

acre

acre

Payment at Closing [Member]

Payment Remaining [Member]

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

Mcfe

acre

mi

Mcfe

acre

Mcfe

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from divestitures of proved and unproved properties

$3,467,000,000

$5,884,000,000

$7,651,000,000

'

'

$376,000,000

$540,000,000

$572,000,000

$358,000,000

$490,000,000

$257,000,000

$617,000,000

$3,091,000,000

$64,000,000

$466,000,000

$47,000,000

$32,000,000

$355,000,000

$320,000,000

$42,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$350,000,000

$4,650,000,000

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

Gas and Oil Area, Developed, Gross

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

850,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas and Oil Area, Developed, Net

'

'

'

9,600

55,000

'

40,000

60,000

72,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

425,000

'

'

'

'

'

'

'

Percentage Of Estimated Proved Reserves

'

'

'

'

'

6.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proved Developed Reserves (Energy)

1,334,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

28,000,000

'

'

Proceeds from Divestiture of Interest in Joint Venture

8,049,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8,000,000,000

'

58,000,000

272,000,000

511,000,000

'

949,000,000

949,000,000

1,020,000,000

71,000,000

90,000,000

313,000,000

'

'

'

Percentage of Total Payment by Joint Venture Partner

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

7.00%

'

'

'

'

'

Number of Joint Ventures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Drilling Carries

9,035,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0

'

'

'

'

'

'

'

'

Oil And Gas Benefit From Drilling Carries

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2,570,000,000

884,000,000

784,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Sale of Other Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

'

'

'

'

$7,000,000

Net Acres Sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

487,000

487,000

Current Net Production (Unit)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

415

415

Length Of Pipeline

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

420

Investments_Schedule_of_Invest

Investments - Schedule of Investments Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]	'	'
Investments	$477	$728
FTS International, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	30.00%	30.00%
Equity Method Investments	138	298
Chaparral Energy, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	20.00%	20.00%
Equity Method Investments	143	141
Sundrop Fuels, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	56.00%	50.00%
Equity Method Investments	135	111
Clean Energy Fuels Corp.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Cost method percentage approximate owned	0.00%	0.00%
Fair Value Method Investment Ownership Percentage	0.00%	1.00%
Cost Method Investments	0	100
Fair Value Method Investments	0	12
Gastar Exploration Ltd.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Fair Value Method Investment Ownership Percentage	0.00%	10.00%
Fair Value Method Investments	0	8
Other Investment Companies [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	0.00%	0.00%
Cost Method Investments	$61	$58

Investments_Investments_Schedu

Investments Investments - Schedule of Equity Method Investments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]	'	'	'
Equity Method Investment, Summarized Financial Information, Current Assets	$521	$892	$732
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	1,859	4,225	5,175
Equity Method Investment, Summarized Financial Information, Current Liabilities	192	207	277
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	1,468	1,726	1,916
Equity Method Investment, Summarized Financial Information, Revenue	1,807	2,190	2,209
Equity Method Investment, Summarized Financial Information, Cost of Sales	3,926	3,089	1,630
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	($2,459)	($968)	$494

Investments_Narrative_Details

Investments - Narrative (Details) (USD $)

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

0 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jan. 14, 2014

Dec. 31, 2013

FTS International, Inc.

FTS International, Inc.

Chaparral Energy, Inc.

Chaparral Energy, Inc.

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Clean Energy Fuels Corp.

Clean Energy Fuels Corp.

Gastar Exploration Ltd.

Gastar Exploration Ltd.

Chesapeake Midstream Partners Lp [Member]

Glass Mountain Pipeline Limited Liability Company [Member]

Glass Mountain Pipeline Limited Liability Company [Member]

Other Investment Companies [Member]

Other Investment Companies [Member]

Sale of Chaparral Energy [Member]

Final Investment [Member]

mi

Chaparral Energy, Inc.

Sundrop Fuels, Inc.

Schedule of Equity Method Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost method percentage approximate owned

'

'

'

'

'

'

'

'

'

0.00%

0.00%

'

'

'

'

'

'

'

'

'

Positive equity method adjustments

'

'

'

$177

'

$10

'

$16

'

'

'

'

'

$46

'

'

'

'

'

'

Equity method accretion adjustments

'

'

'

14

'

'

'

'

'

'

'

'

'

4

'

'

'

'

'

'

Excess carrying value of investment over underlying equity in net assets

'

'

'

54

'

48

'

62

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

14

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Goodwill, Not Allocated, Amount

'

'

'

282

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Commitment, Due in Next Twelve Months

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Depreciation

'

'

'

'

'

5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity method depreciation adjustments

'

'

'

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Sale of Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

215

'

Net gains on sales of fixed assets

-302

-267

-437

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Method Investments

'

'

'

138

298

143

141

135

111

'

'

'

'

'

'

'

'

'

'

40

Cost Method Investments

'

'

'

'

'

'

'

'

'

0

100

'

'

'

'

'

61

58

'

'

Proceeds from Cost Method Investment

'

'

'

'

'

'

'

'

'

85

'

'

'

'

'

'

'

'

'

'

Impairment of investment

'

'

'

'

'

'

'

'

'

15

'

'

'

'

'

'

'

'

'

'

Gains (losses) on sales of investments

'

'

'

'

'

'

'

'

'

3

'

'

'

'

62

'

5

'

'

'

Sale of Stock, Consideration Received on Transaction

'

'

'

'

'

'

'

'

'

13

'

10

'

'

'

'

6

'

'

'

Other Commitment

'

'

'

'

'

'

'

'

'

50

'

'

'

'

'

'

'

'

'

'

Additional Assets Pipeline Length

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

210

'

'

'

'

Equity Method Investment, Ownership Percentage

'

'

'

30.00%

30.00%

20.00%

20.00%

56.00%

50.00%

'

'

'

'

'

'

50.00%

0.00%

0.00%

'

'

Distributions From Equity Investments

'

'

'

'

'

'

'

'

'

'

'

'

'

56

'

'

'

'

'

'

Proceeds from sales of investments

115

2,000

0

'

'

'

'

'

'

'

'

'

'

2,000

'

99

'

'

215

'

Equity Method Investment, Realized Gain (Loss) on Disposal

'

'

'

'

'

'

'

'

'

'

'

'

'

1,032

'

'

'

'

'

'

Equity Method Investment, Deferred Gain on Sale

'

'

'

'

'

'

'

'

'

'

'

'

'

$13

'

'

'

'

'

'

Fair Value Method Investment Ownership Percentage

'

'

'

'

'

'

'

'

'

0.00%

1.00%

0.00%

10.00%

'

'

'

'

'

'

'

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013
Chesapeake Granite Wash Trust | Consolidated Entities	'
Variable Interest Entity [Line Items]	'
Consolidation Net Oil and Gas Property Assets	320
Other current liabilities attributable to our VIEs	22
Cash and cash equivalents attributable to our VIEs	1
Short-term derivative liabilities attributable to our VIEs	5
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member] | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of acquisition	10.00%
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member] | Minimum | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of royalty minimum	7.00%
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member] | Maximum | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Other Commitment	25
Percentage of royalty maximum	22.50%
Mineral Acquisition Company I, L.P. | Partner Ownership Requirement [Member] | Limited Partner [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of acquisition	90.00%
Mineral Acquisition Company I, L.P. | Partner Ownership Requirement [Member] | 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 - Other Properties Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Oilfield services equipment	$2,192	$2,130
Property and equipment, other	5,395	5,908
Accumulated Depreciation And Amortization Of Other Property And Equipment	-1,584	-1,293
Total Other Property And Equipment, Net	3,811	4,615
Oilfield Services Equipment [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Oilfield services equipment	2,192	2,130
Property, Plant and Equipment, Estimated Useful Lives	'3 - 15	'
Building and Improvements [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Buildings and Improvements, Gross	1,433	1,580
Property, Plant and Equipment, Estimated Useful Lives	'10 - 39	'
Natural Gas Compressors [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Machinery and Equipment, Gross	368	505
Property, Plant and Equipment, Estimated Useful Lives	'3 - 20	'
Land [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Land	212	515
Property, Plant and Equipment, Estimated Useful Lives	'0	'
Property, Plant and Equipment, Other Types	'	'
Property, Plant and Equipment [Line Items]	'	'
Property and Equipment Other Miscellaneous	$1,190	$1,178
Property, Plant and Equipment, Estimated Useful Lives	'2 - 20	'

Other_Property_and_Equipment_O1

Other Property and Equipment Other Property and Equipment Net Gains (Losses) on Sales of Fixed Assets Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]	'	'	'
Net gains on sales of fixed assets	($302)	($267)	($437)
Gas Gathering and Processing Equipment [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Net gains on sales of fixed assets	-326	-286	-440
Exploration and Production Equipment [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Net gains on sales of fixed assets	2	10	1
Land and Building [Member]	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Net gains on sales of fixed assets	27	7	2
Other Assets	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'
Net gains on sales of fixed assets	($5)	$2	$0

Other_Property_and_Equipment_O2

Other Property and Equipment Other Property and Equipment - Assets Held For Sale Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Long Lived Assets Held-for-sale [Line Items]	'	'
Current assets held for sale	$0	$4
Property and equipment held for sale, net	730	634
Current liabilities held for sale	0	21
Compressor [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	285	0
Accounts Receivable [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Current assets held for sale	0	4
Natural Gas Processing Plant [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	11	352
Exploration and Production Equipment [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	29	27
Property, Plant and Equipment, Other Types	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	405	255
Accounts Payable [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Current liabilities held for sale	0	4
Accrued Liabilities [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Current liabilities held for sale	$0	$17

Other_Property_and_Equipment_N1

Other Property and Equipment - Narrative (Details) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

1 Months Ended

12 Months Ended

In Millions, except Per Share data, unless otherwise specified

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Jun. 30, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2013

Chesapeake Midstream Operating [Member]

Chesapeake Midstream Operating [Member]

Midstream Eagle Ford Oil Gathering Assets [Member]

Midstream Eagle Ford Oil Gathering Assets [Member]

Midstream Eagle Ford Oil Gathering Assets [Member]

Bronco Drilling Company Incorporated [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Land and Building [Member]

Land and Building [Member]

Land and Building [Member]

Chesapeake Midstream Development L P [Member]

Chesapeake Midstream Development L P [Member]

Chesapeake Midstream Development L P [Member]

Common Stock

Subsequent Payment [Member]

Cash Payment [Member]

Sale to SemGas, L.P. [Member]

Sale to MarkWest Oklahoma Gas Company L.L.C. [Member]

Sale to Western Gas Partners, LP [Member]

Appalachia Midstream Services, L.L.C. [Member]

Appalachia Midstream Services, L.L.C. [Member]

Appalachia Midstream Services, L.L.C. [Member]

Property, Plant and Equipment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Sale of Property, Plant, and Equipment

'

'

'

'

'

'

$10

$115

'

'

'

'

$306

$252

$134

'

'

'

'

'

'

Net gains on sales of fixed assets

-302

-267

-437

289

'

3

'

'

'

-326

-286

-440

141

105

55

27

7

2

'

'

'

Gathering Fee Escalation Rate

'

'

'

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Disposition of Assets for Financial Service Operations

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

439

'

Proceeds from Divestiture of Businesses and Interests in Affiliates

'

'

'

'

2,160

'

'

'

'

'

'

'

'

'

'

'

'

'

884

'

'

Contract Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'15 years

Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds

'

'

'

'

'

'

'

'

$339

'

'

'

'

'

'

'

'

'

'

'

'

Share Price

'

'

'

'

'

'

'

'

$11

'

'

'

'

'

'

'

'

'

'

'

'

Impairments_Table_Details

Impairments - Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Impairments of fixed assets and other	$546	$340	$46
Land and Building [Member]	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Impairments of fixed assets and other	366	248	3
Exploration and Production Equipment [Member]	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Impairments of fixed assets and other	71	60	0
Gas Gathering and Processing Equipment [Member]	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Impairments of fixed assets and other	22	6	43
Other Assets	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'
Impairments of fixed assets and other	$87	$26	$0

Impairments_Narrative_Details

Impairments - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2012
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of natural gas and oil properties	$0	$3,315	$0	'
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	'	'	'	279
Impairments of fixed assets and other	546	340	46	'
Other Asset Impairment Charges	87	'	'	'
Third Party [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Gain (Loss) on Contract Termination	15	'	'	'
Net Acreage Maintenance Commitment [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Other Asset Impairment Charges	2	26	'	'
Drilling Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Number of repurchased equipment	23	'	'	'
Payments to Acquire Property, Plant, and Equipment	141	'	'	'
Repurchase of Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Equipment Owned	'	25	'	'
Assets Held-for-sale [Member] | Drilling Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Number of repurchased equipment	2	'	'	'
Leasehold Improvements [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	22	'	'	'
Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	366	248	3	'
Drilling Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	27	26	'	'
Payments to Acquire Property, Plant, and Equipment	141	'	'	'
Gain (Loss) on Contract Termination	22	'	'	'
Drilling Rigs [Member] | Repurchase of Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Payments to Acquire Property, Plant, and Equipment	'	36	'	'
Gain (Loss) on Contract Termination	'	25	'	'
Tubular Goods [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	'	9	'	'
Gas Gathering and Processing Equipment [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	22	6	43	'
Impairments of fixed assets and other	22	6	43	'
Other Asset Impairment Charges	26	'	'	'
Property, Plant and Equipment, Other Types	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Other Asset Impairment Charges	16	'	'	'
Selling and Marketing Expense [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Other Asset Impairment Charges	28	'	'	'
In the Oklahoma City Area [Member] | Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	69	'	'	'
In the Oklahoma City Area [Member] | Land and Building [Member] | Assets Held-for-sale [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	186	'	'	'
In the Fort Worth Area [Member] | Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	'	10	'	'
In the Fort Worth Area [Member] | Land and Building [Member] | Assets Held-for-sale [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	86	'	'	'
Outside the Oklahoma City Area [Member] | Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairments of fixed assets and other	$15	'	'	'

Restructuring_and_Other_Termin1

Restructuring and Other Termination Benefits - Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	$50	$5	$0
Restructuring and other termination costs	248	7	0
Ceo Aubrey K Mcclendon [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	69	0	0
Ceo Aubrey K Mcclendon [Member] | Cash Salary and Bonus Costs [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	11	0	0
Ceo Aubrey K Mcclendon [Member] | Claw-Back Bonus [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	11	0	0
Ceo Aubrey K Mcclendon [Member] | Acceleration of Restricted Stock Awards [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	22	0	0
Ceo Aubrey K Mcclendon [Member] | Acceleration of Performance Shares [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	18	0	0
Ceo Aubrey K Mcclendon [Member] | Other Costs Associated with Retirement [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	7	0	0
Workforce Reduction Plan [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Restructuring and Related Cost, Incurred Cost	66	0	0
Workforce Reduction Plan [Member] | Salary Expense [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Restructuring and Related Cost, Incurred Cost	20	0	0
Workforce Reduction Plan [Member] | Acceleration of Stock-Based Compensation Awards [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Restructuring and Related Cost, Incurred Cost	45	0	0
Workforce Reduction Plan [Member] | Other Costs Associated with Retirement [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Restructuring and Related Cost, Incurred Cost	1	0	0
VSP Program	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	63	2	0
VSP Program | Cash Salary and Bonus Costs [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	33	1	0
VSP Program | Acceleration of Restricted Stock Awards [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	29	1	0
VSP Program | Other Costs Associated with Retirement [Member]	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'
Severance Costs	$1	$0	$0

Restructuring_and_Other_Termin2

Restructuring and Other Termination Benefits - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 07, 2013
		Employee		Employee
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Restructuring and Related Cost, Number of Positions Eliminated	900	'	'	'
Severance Costs	$50	$5	$0	'
Ceo Aubrey K Mcclendon [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Severance Costs	69	0	0	'
Workforce Reduction Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	66	0	0	'
VSP Program	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Severance Costs	$63	$2	$0	'
Number of Employees Selected for Voluntary Program	'	275	'	'
Number of Employees That Selected Voluntary Program	'	'	'	211

Fair_Value_Measurements_Financ

Fair Value Measurements - Financial Assets/Liabilities Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total derivatives	($649)	($979)
Total	-651	-954
Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	40	115
Commodity liabilities	-593	-1,039
Interest rate contract	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Interest rate liabilities	-98	-35
Foreign currency contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Foreign currency liabilities	2	-20
Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other current assets	80	4
Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	-82	'
Investments [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Investments	'	20
Other Noncurrent Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other long-term assets	'	88
Other Noncurrent Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	'	-87
Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total derivatives	0	0
Total	-2	25
Fair Value, Inputs, Level 1 [Member] | Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	0	0
Commodity liabilities	0	0
Fair Value, Inputs, Level 1 [Member] | Interest rate contract	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Interest rate liabilities	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign currency contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Foreign currency liabilities	0	0
Fair Value, Inputs, Level 1 [Member] | Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other current assets	80	4
Fair Value, Inputs, Level 1 [Member] | Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	-82	'
Fair Value, Inputs, Level 1 [Member] | Investments [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Investments	'	20
Fair Value, Inputs, Level 1 [Member] | Other Noncurrent Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other long-term assets	'	88
Fair Value, Inputs, Level 1 [Member] | Other Noncurrent Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	'	-87
Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total derivatives	-171	37
Total	-171	37
Fair Value, Inputs, Level 2 [Member] | Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	25	105
Commodity liabilities	-100	-13
Fair Value, Inputs, Level 2 [Member] | Interest rate contract	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Interest rate liabilities	-98	-35
Fair Value, Inputs, Level 2 [Member] | Foreign currency contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Foreign currency liabilities	2	-20
Fair Value, Inputs, Level 2 [Member] | Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other current assets	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]	'	'
Obligations, fair value disclosure	0	'
Fair Value, Inputs, Level 2 [Member] | Investments [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Investments	'	0
Fair Value, Inputs, Level 2 [Member] | Other Noncurrent Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other long-term assets	'	0
Fair Value, Inputs, Level 2 [Member] | Other Noncurrent Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	'	0
Fair Value, Inputs, Level 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total derivatives	-478	-1,016
Total	-478	-1,016
Fair Value, Inputs, Level 3 [Member] | Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	15	10
Commodity liabilities	-493	-1,026
Fair Value, Inputs, Level 3 [Member] | Interest rate contract	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Interest rate liabilities	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign currency contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Foreign currency liabilities	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 current assets	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]	'	'
Obligations, fair value disclosure	0	'
Fair Value, Inputs, Level 3 [Member] | Investments [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Investments	'	0
Fair Value, Inputs, Level 3 [Member] | Other Noncurrent Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other long-term assets	'	0
Fair Value, Inputs, Level 3 [Member] | Other Noncurrent Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	'	$0

Fair_Value_Measurements_Unobse

Fair Value Measurements - Unobservable Input Or Level 3 Table and Footnote (Details) (USD $)

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 30, 2013

Dec. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 30, 2013

Dec. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

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, Oil and NGL sales

Natural Gas, Oil and NGL sales

Interest Expense

Interest Expense

Commodity contracts

Commodity contracts

Commodity contracts

Commodity contracts

Commodity contracts

Interest rate contract

Interest rate contract

Interest rate contract

Interest rate contract

Interest rate contract

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning balance

$0

'

'

'

'

'

'

($478)

($1,016)

($1,654)

'

'

$0

$0

$0

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

'

410

567

-1

6

410

567

'

'

'

-1

6

'

'

'

Sales

'

'

'

'

'

0

0

'

'

'

1

-6

'

'

'

Settlements

'

'

'

'

'

128

71

'

'

'

0

0

'

'

'

Ending balance

0

'

'

'

'

'

'

-478

-1,016

-1,654

'

'

0

0

0

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

'

$382

$374

$0

$0

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Level_

Fair Value Measurements - Level 3 Table and Phantom (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2013
Crude Oil [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Fair Value Assets Unobservable Input Description	'Oil price volatility curves
Weighted Average Of Price Volatility Curve Percentage	13.62%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	($265)
Crude Oil [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	0.00%
Crude Oil [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	23.65%
Natural Gas [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Fair Value Assets Unobservable Input Description	'Natural gas price volatility curves
Weighted Average Of Price Volatility Curve Percentage	22.49%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-217
Natural Gas [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	17.75%
Natural Gas [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	60.88%
Basis Swap [Member] | Crude Oil [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Fair Value Assets Unobservable Input Description	'Physical pricing point forward curves
Weighted Average Of Price Forward Curve	$3.74
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	1
Basis Swap [Member] | Crude Oil [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	3.51
Basis Swap [Member] | Crude Oil [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	4.41
Basis Swap [Member] | Natural Gas [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Fair Value Assets Unobservable Input Description	'Physical pricing point forward curves
Weighted Average Of Price Forward Curve	($0.46)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$3
Basis Swap [Member] | Natural Gas [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	-1.03
Basis Swap [Member] | Natural Gas [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	-0.11

Fair_Value_Measurements_Carryi

Fair Value Measurements - Carrying Value Excluding Impact of Interest Rate Derivatives Table (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Current maturities of long-term debt, net	$0	$463
Long-term Debt	13,230	'
Carrying Amount | Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Current maturities of long-term debt, net	0	463
Long-term Debt	10,501	9,759
Carrying Amount | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	2,372	2,378
Estimated Fair Value | Fair Value, Inputs, Level 1 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Current maturities of long-term debt, net	0	480
Long-term Debt	11,557	10,457
Estimated Fair Value | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	$2,369	$2,284

Asset_Retirement_Obligations_A

Asset Retirement Obligations Asset Retirement Obligations - Changes in Asset Retirement Obligations Table (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 30, 2013	Dec. 30, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Asset Retirement Obligation Disclosure [Abstract]	'	'	'	'	'
Asset Retirement Obligation Period Start	'	'	$405	$375	$323
Asset Retirement Obligation, Liabilities Incurred	20	29	'	'	'
Asset Retirement Obligation, Revision of Estimate	8	42	'	'	'
Asset Retirement Obligation, Liabilities Settled	-20	-41	'	'	'
Asset Retirement Obligation, Accretion Expense	22	22	'	'	'
Asset Retirement Obligation Period End	'	'	$405	$375	$323

Segment_Reporting_Table_Detail

Segment Reporting - Table (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]	'	'	'
Revenues	$17,506,000,000	$12,316,000,000	$11,635,000,000
Depreciation, depletion and amortization	2,903,000,000	2,811,000,000	1,923,000,000
Impairment of natural gas and oil properties	0	3,315,000,000	0
Impairments of fixed assets and other	546,000,000	340,000,000	46,000,000
Interest expense	-227,000,000	-77,000,000	-44,000,000
Earnings (losses) on investments	-226,000,000	-103,000,000	156,000,000
Gains (losses) on sales of investments	-7,000,000	1,092,000,000	0
Losses on purchases of debt and extinguishment of other financing	-193,000,000	-200,000,000	-176,000,000
Income (Loss) Before Income Taxes	1,442,000,000	-974,000,000	2,880,000,000
Total Assets	41,782,000,000	41,611,000,000	'
Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	7,052,000,000	6,278,000,000	6,024,000,000
Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	9,559,000,000	5,431,000,000	5,090,000,000
Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	879,000,000	602,000,000	521,000,000
Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	16,000,000	5,000,000	0
Reportable Subsegments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	17,506,000,000	12,316,000,000	11,635,000,000
Unrealized Gain (Loss) on Derivatives	-228,000,000	-561,000,000	789,000,000
Depreciation, depletion and amortization	2,903,000,000	2,811,000,000	1,923,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	-302,000,000	-267,000,000	-437,000,000
Impairment of natural gas and oil properties	'	3,315,000,000	'
Impairments of fixed assets and other	546,000,000	340,000,000	46,000,000
Interest expense	-227,000,000	-77,000,000	-44,000,000
Earnings (losses) on investments	-226,000,000	-103,000,000	156,000,000
Gains (losses) on sales of investments	-7,000,000	1,092,000,000	'
Losses on purchases of debt and extinguishment of other financing	-193,000,000	-200,000,000	-176,000,000
Income (Loss) Before Income Taxes	1,442,000,000	-974,000,000	2,880,000,000
Total Assets	41,782,000,000	41,611,000,000	41,835,000,000
Payments to Acquire Productive Assets	7,190,000,000	14,108,000,000	14,561,000,000
Intersubsegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	0
Operating Segments [Member] | Reportable Subsegments [Member] | Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	7,052,000,000	6,278,000,000	6,024,000,000
Unrealized Gain (Loss) on Derivatives	-228,000,000	-561,000,000	789,000,000
Depreciation, depletion and amortization	2,674,000,000	2,624,000,000	1,759,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	2,000,000	14,000,000	3,000,000
Impairment of natural gas and oil properties	'	3,315,000,000	'
Impairments of fixed assets and other	27,000,000	28,000,000	0
Interest expense	-918,000,000	-47,000,000	-42,000,000
Earnings (losses) on investments	3,000,000	0	0
Gains (losses) on sales of investments	0	-2,000,000	'
Losses on purchases of debt and extinguishment of other financing	-193,000,000	-200,000,000	-176,000,000
Income (Loss) Before Income Taxes	2,997,000,000	-1,798,000,000	2,561,000,000
Total Assets	35,341,000,000	37,004,000,000	35,403,000,000
Payments to Acquire Productive Assets	6,198,000,000	12,044,000,000	12,201,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	17,129,000,000	10,895,000,000	10,336,000,000
Unrealized Gain (Loss) on Derivatives	0	0	0
Depreciation, depletion and amortization	46,000,000	54,000,000	55,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	-329,000,000	-298,000,000	-441,000,000
Impairment of natural gas and oil properties	'	0	'
Impairments of fixed assets and other	50,000,000	6,000,000	43,000,000
Interest expense	-24,000,000	-20,000,000	-15,000,000
Earnings (losses) on investments	0	49,000,000	95,000,000
Gains (losses) on sales of investments	0	1,094,000,000	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Income (Loss) Before Income Taxes	511,000,000	1,665,000,000	745,000,000
Total Assets	2,430,000,000	2,291,000,000	4,047,000,000
Payments to Acquire Productive Assets	299,000,000	852,000,000	1,219,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	2,188,000,000	1,917,000,000	1,258,000,000
Unrealized Gain (Loss) on Derivatives	0	0	0
Depreciation, depletion and amortization	289,000,000	232,000,000	172,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	-1,000,000	10,000,000	1,000,000
Impairment of natural gas and oil properties	'	0	'
Impairments of fixed assets and other	75,000,000	60,000,000	3,000,000
Interest expense	-82,000,000	-76,000,000	-48,000,000
Earnings (losses) on investments	-1,000,000	0	0
Gains (losses) on sales of investments	0	0	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Income (Loss) Before Income Taxes	-51,000,000	112,000,000	72,000,000
Total Assets	2,018,000,000	2,115,000,000	1,571,000,000
Payments to Acquire Productive Assets	272,000,000	658,000,000	657,000,000
Operating Segments [Member] | Reportable Subsegments [Member] | Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	29,000,000	21,000,000	0
Unrealized Gain (Loss) on Derivatives	0	0	0
Depreciation, depletion and amortization	49,000,000	46,000,000	37,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	26,000,000	7,000,000	0
Impairment of natural gas and oil properties	'	0	'
Impairments of fixed assets and other	394,000,000	246,000,000	0
Interest expense	-74,000,000	-364,000,000	-195,000,000
Earnings (losses) on investments	-229,000,000	-152,000,000	61,000,000
Gains (losses) on sales of investments	-7,000,000	0	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Income (Loss) Before Income Taxes	-727,000,000	-478,000,000	-168,000,000
Total Assets	5,750,000,000	2,529,000,000	2,718,000,000
Payments to Acquire Productive Assets	421,000,000	554,000,000	484,000,000
Intersegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	0
Intersegment Eliminations [Member] | Exploration and Production	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	0
Intersegment Eliminations [Member] | Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-7,570,000,000	-5,464,000,000	-5,246,000,000
Intersegment Eliminations [Member] | Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-1,309,000,000	-1,315,000,000	-737,000,000
Intersegment Eliminations [Member] | Other Segments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-13,000,000	-16,000,000	0
Intersegment Eliminations [Member] | Reportable Subsegments [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-8,892,000,000	-6,795,000,000	-5,983,000,000
Unrealized Gain (Loss) on Derivatives	0	0	0
Depreciation, depletion and amortization	-155,000,000	-145,000,000	-100,000,000
Gain (Loss) on Disposition of Assets for Financial Service Operations	0	0	0
Impairment of natural gas and oil properties	'	0	'
Impairments of fixed assets and other	0	0	0
Interest expense	871,000,000	430,000,000	256,000,000
Earnings (losses) on investments	1,000,000	0	0
Gains (losses) on sales of investments	0	0	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Income (Loss) Before Income Taxes	-1,288,000,000	-475,000,000	-330,000,000
Total Assets	-3,757,000,000	-2,328,000,000	-1,904,000,000
Payments to Acquire Productive Assets	0	0	0
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	$8,892,000,000	$6,795,000,000	$5,983,000,000

Segment_Information_Narrative_

Segment Information - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Segment
Segment Reporting Information [Line Items]	'	'	'
Concentration Risk, Percentage	'	11.00%	0.00%
Segment Reporting, Disclosure of Major Customers	'0	'	'0
Number of reportable segments	3	'	'
Revenues	($17,506)	($12,316)	($11,635)
Intersegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	0	0	0
Marketing, Gathering And Compression	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-9,559	-5,431	-5,090
Marketing, Gathering And Compression | Intersegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	7,570	5,464	5,246
Oilfield Services	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	-879	-602	-521
Oilfield Services | Intersegment Eliminations [Member]	'	'	'
Segment Reporting Information [Line Items]	'	'	'
Revenues	$1,309	$1,315	$737

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheet (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$837	$287	$351	$102
Restricted cash	75	111	'	'
Other	2,744	2,546	'	'
Current assets held for sale	0	4	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	3,656	2,948	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	32,593	31,918	'	'
Other property and equipment, net	3,811	4,615	'	'
Property and equipment held for sale, net	730	634	'	'
Total Property and Equipment, Net	37,134	37,167	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	992	1,496	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	41,782	41,611	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,515	6,245	'	'
Current liabilities held for sale	0	21	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	5,515	6,266	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	12,886	12,157	'	'
Deferred income tax liabilities	3,407	2,807	'	'
Other long-term liabilities	1,834	2,485	'	'
Total Long-Term Liabilities	18,127	17,449	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	15,995	15,569	'	'
Noncontrolling interests	2,145	2,327	'	'
Total Equity	18,140	17,896	17,961	'
TOTAL LIABILITIES AND EQUITY	41,782	41,611	'	'
Parent	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	799	228	2	1
Restricted cash	0	0	'	'
Other	103	1	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	25,385	25,159	'	'
Total Current Assets	26,287	25,388	'	'
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	111	217	'	'
Investments in subsidiaries and intercompany advances	2,333	2,438	'	'
TOTAL ASSETS	28,731	28,043	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	300	789	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	300	789	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	11,831	11,089	'	'
Deferred income tax liabilities	209	361	'	'
Other long-term liabilities	396	235	'	'
Total Long-Term Liabilities	12,436	11,685	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	15,995	15,569	'	'
Noncontrolling interests	0	0	'	'
Total Equity	15,995	15,569	'	'
TOTAL LIABILITIES AND EQUITY	28,731	28,043	'	'
Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0	'	'
Other	2,395	2,382	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	2,395	2,382	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	29,295	28,742	'	'
Other property and equipment, net	2,317	3,065	'	'
Property and equipment held for sale, net	701	256	'	'
Total Property and Equipment, Net	32,313	32,063	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	1,146	1,396	'	'
Investments in subsidiaries and intercompany advances	-235	-134	'	'
TOTAL ASSETS	35,619	35,707	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,196	5,377	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	24,814	23,684	'	'
Total Current Liabilities	30,010	29,061	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	2,254	2,425	'	'
Other long-term liabilities	1,022	1,783	'	'
Total Long-Term Liabilities	3,276	4,208	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	2,333	2,438	'	'
Noncontrolling interests	0	0	'	'
Total Equity	2,333	2,438	'	'
TOTAL LIABILITIES AND EQUITY	35,619	35,707	'	'
Non-Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	39	59	349	101
Restricted cash	82	111	'	'
Other	613	511	'	'
Current assets held for sale	0	4	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	734	685	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	3,113	3,387	'	'
Other property and equipment, net	1,495	1,551	'	'
Property and equipment held for sale, net	29	378	'	'
Total Property and Equipment, Net	4,637	5,316	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	111	261	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	5,482	6,262	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	378	428	'	'
Current liabilities held for sale	'	21	'	'
Intercompany payable, net	474	1,586	'	'
Total Current Liabilities	852	2,035	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	1,055	1,068	'	'
Deferred income tax liabilities	857	127	'	'
Other long-term liabilities	877	839	'	'
Total Long-Term Liabilities	2,789	2,034	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	1,841	2,193	'	'
Noncontrolling interests	0	0	'	'
Total Equity	1,841	2,193	'	'
TOTAL LIABILITIES AND EQUITY	5,482	6,262	'	'
Eliminations	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	-1	0	0	0
Restricted cash	-7	0	'	'
Other	-367	-348	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	-25,385	-25,159	'	'
Total Current Assets	-25,760	-25,507	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	185	-211	'	'
Other property and equipment, net	-1	-1	'	'
Property and equipment held for sale, net	0	0	'	'
Total Property and Equipment, Net	184	-212	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	-376	-378	'	'
Investments in subsidiaries and intercompany advances	-2,098	-2,304	'	'
TOTAL ASSETS	-28,050	-28,401	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	-359	-349	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	-25,288	-25,270	'	'
Total Current Liabilities	-25,647	-25,619	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	87	-106	'	'
Other long-term liabilities	-461	-372	'	'
Total Long-Term Liabilities	-374	-478	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	-4,174	-4,631	'	'
Noncontrolling interests	2,145	2,327	'	'
Total Equity	-2,029	-2,304	'	'
TOTAL LIABILITIES AND EQUITY	($28,050)	($28,401)	'	'

Condensed_Consolidating_Statem

Condensed Consolidating Statement Of Operations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
REVENUES	'	'	'
Natural gas, oil and NGL	$7,052	$6,278	$6,024
Marketing, gathering and compression	9,559	5,431	5,090
Oilfield services	895	607	521
Total Revenues	17,506	12,316	11,635
OPERATING EXPENSES	'	'	'
Natural gas, oil and NGL production	1,159	1,304	1,073
Production taxes	229	188	192
Marketing, gathering and compression	9,461	5,312	4,967
Oilfield services	736	465	402
General and administrative	457	535	548
Restructuring and other termination costs	248	7	0
Natural gas, oil and NGL depreciation, depletion and amortization	2,589	2,507	1,632
Depreciation and amortization of other assets	314	304	291
Impairment of natural gas and oil properties	0	3,315	0
Impairments of fixed assets and other	546	340	46
Net gains on sales of fixed assets	-302	-267	-437
Total Operating Expenses	15,437	14,010	8,714
INCOME (LOSS) FROM OPERATIONS	2,069	-1,694	2,921
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	-227	-77	-44
Earnings (losses) on investments	-226	-103	156
Gains (losses) on sales of investments	-7	1,092	0
Losses on purchases of debt and extinguishment of other financing	-193	-200	-176
Other income	26	8	23
Equity in net earnings of subsidiary	0	0	0
Total Other Income (Expense)	-627	720	-41
INCOME (LOSS) BEFORE INCOME TAXES	1,442	-974	2,880
INCOME TAX EXPENSE (BENEFIT)	548	-380	1,123
NET INCOME (LOSS)	894	-594	1,757
Net income attributable to noncontrolling interests	-170	-175	-15
Net income (loss) attributable to Chesapeake	724	-769	1,742
Other Comprehensive Income (Loss), Net of Tax	20	-16	2
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	744	-785	1,744
Parent	'	'	'
REVENUES	'	'	'
Natural gas, oil and NGL	0	0	0
Marketing, gathering and compression	0	0	0
Oilfield services	0	0	0
Total Revenues	0	0	0
OPERATING EXPENSES	'	'	'
Natural gas, oil and NGL production	0	0	0
Production taxes	0	0	0
Marketing, gathering and compression	0	0	0
Oilfield services	0	0	0
General and administrative	0	0	0
Restructuring and other termination costs	0	0	'
Natural gas, oil and NGL depreciation, depletion and amortization	0	0	0
Depreciation and amortization of other assets	0	0	0
Impairment of natural gas and oil properties	0	0	'
Impairments of fixed assets and other	0	0	0
Net gains on sales of fixed assets	0	0	0
Total Operating Expenses	0	0	0
INCOME (LOSS) FROM OPERATIONS	0	0	0
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	-921	-879	-640
Earnings (losses) on investments	0	0	0
Gains (losses) on sales of investments	0	0	'
Losses on purchases of debt and extinguishment of other financing	-70	-200	-176
Other income	3,979	819	646
Equity in net earnings of subsidiary	-1,129	-610	1,846
Total Other Income (Expense)	1,859	-870	1,676
INCOME (LOSS) BEFORE INCOME TAXES	1,859	-870	1,676
INCOME TAX EXPENSE (BENEFIT)	1,135	-101	-66
NET INCOME (LOSS)	724	-769	1,742
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	724	-769	1,742
Other Comprehensive Income (Loss), Net of Tax	3	6	9
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	727	-763	1,751
Guarantor Subsidiaries	'	'	'
REVENUES	'	'	'
Natural gas, oil and NGL	6,289	5,819	5,886
Marketing, gathering and compression	9,549	5,370	5,022
Oilfield services	0	0	18
Total Revenues	15,838	11,189	10,926
OPERATING EXPENSES	'	'	'
Natural gas, oil and NGL production	1,099	1,275	1,073
Production taxes	221	182	190
Marketing, gathering and compression	9,456	5,284	4,944
Oilfield services	95	168	1
General and administrative	361	415	477
Restructuring and other termination costs	244	5	'
Natural gas, oil and NGL depreciation, depletion and amortization	2,303	2,346	1,625
Depreciation and amortization of other assets	177	181	169
Impairment of natural gas and oil properties	0	3,174	'
Impairments of fixed assets and other	443	275	0
Net gains on sales of fixed assets	-301	-269	-2
Total Operating Expenses	14,098	13,036	8,477
INCOME (LOSS) FROM OPERATIONS	1,740	-1,847	2,449
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	-4	45	-12
Earnings (losses) on investments	-225	-167	61
Gains (losses) on sales of investments	-7	1,030	'
Losses on purchases of debt and extinguishment of other financing	-123	0	0
Other income	-594	202	43
Equity in net earnings of subsidiary	-264	-163	309
Total Other Income (Expense)	-1,217	947	401
INCOME (LOSS) BEFORE INCOME TAXES	523	-900	2,850
INCOME TAX EXPENSE (BENEFIT)	299	-287	991
NET INCOME (LOSS)	224	-613	1,859
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	224	-613	1,859
Other Comprehensive Income (Loss), Net of Tax	19	-22	-9
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	243	-635	1,850
Non-Guarantor Subsidiaries	'	'	'
REVENUES	'	'	'
Natural gas, oil and NGL	754	387	84
Marketing, gathering and compression	10	212	199
Oilfield services	2,218	1,941	1,260
Total Revenues	2,982	2,540	1,543
OPERATING EXPENSES	'	'	'
Natural gas, oil and NGL production	60	29	0
Production taxes	8	6	2
Marketing, gathering and compression	5	115	116
Oilfield services	1,761	1,433	958
General and administrative	97	121	71
Restructuring and other termination costs	4	2	'
Natural gas, oil and NGL depreciation, depletion and amortization	286	161	7
Depreciation and amortization of other assets	292	273	217
Impairment of natural gas and oil properties	311	141	'
Impairments of fixed assets and other	103	65	46
Net gains on sales of fixed assets	-1	2	-435
Total Operating Expenses	2,926	2,348	982
INCOME (LOSS) FROM OPERATIONS	56	192	561
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	-85	-84	-50
Earnings (losses) on investments	-1	55	95
Gains (losses) on sales of investments	0	62	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Other income	13	15	19
Equity in net earnings of subsidiary	0	0	0
Total Other Income (Expense)	-73	48	64
INCOME (LOSS) BEFORE INCOME TAXES	-17	240	625
INCOME TAX EXPENSE (BENEFIT)	-6	93	243
NET INCOME (LOSS)	-11	147	382
Net income attributable to noncontrolling interests	0	0	0
Net income (loss) attributable to Chesapeake	-11	147	382
Other Comprehensive Income (Loss), Net of Tax	-2	0	2
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	-13	147	384
Eliminations	'	'	'
REVENUES	'	'	'
Natural gas, oil and NGL	9	72	54
Marketing, gathering and compression	0	-151	-131
Oilfield services	-1,323	-1,334	-757
Total Revenues	-1,314	-1,413	-834
OPERATING EXPENSES	'	'	'
Natural gas, oil and NGL production	0	0	0
Production taxes	0	0	0
Marketing, gathering and compression	0	-87	-93
Oilfield services	-1,120	-1,136	-557
General and administrative	-1	-1	0
Restructuring and other termination costs	0	0	'
Natural gas, oil and NGL depreciation, depletion and amortization	0	0	0
Depreciation and amortization of other assets	-155	-150	-95
Impairment of natural gas and oil properties	-311	0	'
Impairments of fixed assets and other	0	0	0
Net gains on sales of fixed assets	0	0	0
Total Operating Expenses	-1,587	-1,374	-745
INCOME (LOSS) FROM OPERATIONS	273	-39	-89
OTHER INCOME (EXPENSE):	'	'	'
Interest expense	783	841	658
Earnings (losses) on investments	0	9	0
Gains (losses) on sales of investments	0	0	'
Losses on purchases of debt and extinguishment of other financing	0	0	0
Other income	-3,372	-1,028	-685
Equity in net earnings of subsidiary	1,393	773	-2,155
Total Other Income (Expense)	-1,196	595	-2,182
INCOME (LOSS) BEFORE INCOME TAXES	-923	556	-2,271
INCOME TAX EXPENSE (BENEFIT)	-880	-85	-45
NET INCOME (LOSS)	-43	641	-2,226
Net income attributable to noncontrolling interests	-170	-175	-15
Net income (loss) attributable to Chesapeake	-213	466	-2,241
Other Comprehensive Income (Loss), Net of Tax	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	($213)	$466	($2,241)

Condensed_Consolidating_Statem1

Condensed Consolidating Statements Of Cash Flows (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net Cash Provided By Operating Activities	$4,614	$2,837	$5,903
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Acquisitions of proved and unproved properties	-6,636	-12,091	-12,441
Proceeds from divestitures of proved and unproved properties	3,467	5,884	7,651
Additions to other property and equipment	-972	-2,651	-2,009
Other investing activities	1,174	3,874	987
Net Cash Used In Investing Activities	-2,967	-4,984	-5,812
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	7,669	20,318	15,509
Payments on credit facilities borrowings	-7,682	-21,650	-17,466
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263	1,614
Proceeds from issuance of term loans, net of discount and offering costs	0	5,722	0
Repayments of Long-term Debt	-2,141	-4,000	-2,015
Proceeds from sales of noncontrolling interests	6	1,077	1,348
Other financing activities	-1,223	-647	1,168
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	-1,097	2,083	158
Net increase (decrease) in cash and cash equivalents	550	-64	249
Cash and cash equivalents, beginning of period	287	351	102
Cash and cash equivalents, end of period	837	287	351
Parent	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net Cash Provided By Operating Activities	0	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other investing activities	0	0	0
Net Cash Used In Investing Activities	0	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263	977
Proceeds from issuance of term loans, net of discount and offering costs	'	5,722	'
Repayments of Long-term Debt	-2,141	-4,000	-2,015
Proceeds from sales of noncontrolling interests	0	0	0
Other financing activities	1,819	-477	-494
Intercompany advances, net	-1,381	-2,282	1,533
Net Cash Provided By (Used In) Financing Activities	571	226	1
Net increase (decrease) in cash and cash equivalents	571	226	1
Cash and cash equivalents, beginning of period	228	2	1
Cash and cash equivalents, end of period	799	228	2
Guarantor Subsidiaries	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net Cash Provided By Operating Activities	4,115	3,662	5,868
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Acquisitions of proved and unproved properties	-6,226	-11,099	-10,420
Proceeds from divestitures of proved and unproved properties	3,414	5,583	7,651
Additions to other property and equipment	-581	-855	-520
Other investing activities	117	4,705	-348
Net Cash Used In Investing Activities	-3,276	-1,666	-3,637
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	6,452	18,336	14,005
Payments on credit facilities borrowings	-6,452	-20,056	-15,898
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of term loans, net of discount and offering costs	'	0	'
Repayments of Long-term Debt	0	0	0
Proceeds from sales of noncontrolling interests	0	0	0
Other financing activities	-2,809	-153	1,413
Intercompany advances, net	1,970	-123	-1,751
Net Cash Provided By (Used In) Financing Activities	-839	-1,996	-2,231
Net increase (decrease) in cash and cash equivalents	0	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	0	0	0
Non-Guarantor Subsidiaries	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net Cash Provided By Operating Activities	542	431	438
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Acquisitions of proved and unproved properties	-410	-992	-2,021
Proceeds from divestitures of proved and unproved properties	53	301	0
Additions to other property and equipment	-391	-1,796	-1,489
Other investing activities	765	2,133	719
Net Cash Used In Investing Activities	17	-354	-2,791
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	1,217	1,982	1,504
Payments on credit facilities borrowings	-1,230	-1,594	-1,568
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	637
Proceeds from issuance of term loans, net of discount and offering costs	'	0	'
Repayments of Long-term Debt	0	0	0
Proceeds from sales of noncontrolling interests	6	1,077	1,348
Other financing activities	17	-4,237	462
Intercompany advances, net	-589	2,405	218
Net Cash Provided By (Used In) Financing Activities	-579	-367	2,601
Net increase (decrease) in cash and cash equivalents	-20	-290	248
Cash and cash equivalents, beginning of period	59	349	101
Cash and cash equivalents, end of period	39	59	349
Eliminations	'	'	'
Condensed Financial Statements, Captions [Line Items]	'	'	'
Net Cash Provided By Operating Activities	-43	-1,256	-403
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'	'
Acquisitions of proved and unproved properties	0	0	0
Proceeds from divestitures of proved and unproved properties	0	0	0
Additions to other property and equipment	0	0	0
Other investing activities	292	-2,964	616
Net Cash Used In Investing Activities	292	-2,964	616
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'	'
Proceeds from credit facilities borrowings	0	0	0
Payments on credit facilities borrowings	0	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	0	0	0
Proceeds from issuance of term loans, net of discount and offering costs	'	0	'
Repayments of Long-term Debt	0	0	0
Proceeds from sales of noncontrolling interests	0	0	0
Other financing activities	-250	4,220	-213
Intercompany advances, net	0	0	0
Net Cash Provided By (Used In) Financing Activities	-250	4,220	-213
Net increase (decrease) in cash and cash equivalents	-1	0	0
Cash and cash equivalents, beginning of period	0	0	0
Cash and cash equivalents, end of period	($1)	$0	$0

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information Condensed Consolidating Financial Information Narrative (Details)	Dec. 31, 2013
Condensed Financial Statements, Captions [Line Items]	'
Noncontrolling Interest, Ownership Percentage by Parent	50.00%
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 $)	12 Months Ended					0 Months Ended			0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Jan. 14, 2014	Jan. 21, 2014	Jan. 21, 2014	Feb. 20, 2014	Feb. 19, 2014
				Drilling Rigs [Member]	Compressor [Member]	Sale of Chaparral Energy [Member]	Acquisition of Drilling Rigs [Member]	Acquisition of Drilling Rigs [Member]	Acquisition of Compressors [Member]	Acquisition of Compressors [Member]
						Chaparral Energy, Inc.	Drilling Rigs [Member]	Terminated Leases [Member]	Compressor [Member]	Compressor [Member]
							Rigs	Drilling Rigs [Member]	Compressor
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'	'	'
Proceeds from sales of investments	$115	$2,000	$0	'	'	$215	'	'	'	'
Equipment, Number of Units	'	'	'	'	'	'	10	'	576	'
Operating Leases, Future Minimum Payments Due, Next Twelve Months	117	'	'	51	53	'	'	9	'	126
Payments to Acquire Property, Plant, and Equipment	'	'	'	$141	'	'	$31	'	$168	'