Expand Energy (EXE) 10-Q 6 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 04, 2013
Document and Entity Information [Abstract]	'	'
Document Type	'10-Q	'
Amendment Flag	'false	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Trading Symbol	'CHK	'
Entity Registrant Name	'CHESAPEAKE ENERGY CORP	'
Entity Central Index Key	'0000895126	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	665,098,207

CONSOLIDATED_BALANCE_SHEETS

CONSOLIDATED BALANCE SHEETS (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'
Cash and cash equivalents ($1 and $1 attributable to our VIE)	$987	$287
Restricted cash	75	111
Accounts receivable	2,440	2,245
Short-term derivative assets	11	58
Deferred income tax asset	185	90
Other current assets	296	153
Current assets held for sale	0	4
Total Current Assets	3,994	2,948
Natural gas and oil properties, at cost based on full cost accounting:	'	'
Evaluated natural gas and oil properties ($488 and $488 attributable to our VIE)	55,175	50,172
Unevaluated properties	12,282	14,755
Oilfield services equipment	2,179	2,130
Other property and equipment	3,360	3,778
Total Property and Equipment, at Cost	72,996	70,835
Less: accumulated depreciation, depletion and amortization (($151) and ($58) attributable to our VIE)	-36,472	-34,302
Property and equipment held for sale, net	597	634
Total Property and Equipment, Net	37,121	37,167
LONG-TERM ASSETS:	'	'
Investments	615	728
Long-term derivative assets	2	2
Other long-term assets	556	766
TOTAL ASSETS	42,288	41,611
CURRENT LIABILITIES:	'	'
Accounts payable	1,730	1,710
Short-term derivative liabilities ($7 and $4 attributable to our VIE)	170	105
Accrued interest	153	226
Current maturities of long-term debt, net	0	463
Other current liabilities ($24 and $21 attributable to our VIE)	3,625	3,741
Current liabilities held for sale	0	21
Total Current Liabilities	5,678	6,266
LONG-TERM LIABILITIES:	'	'
Long-term debt, net	12,736	12,157
Deferred income tax liabilities	3,423	2,807
Long-term derivative liabilities ($1 and $3 attributable to our VIE)	519	934
Asset retirement obligations	404	375
Other long-term liabilities	1,180	1,176
Total Long-Term Liabilities	18,262	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	12,443	12,293
Retained earnings	905	437
Accumulated other comprehensive loss	-169	-182
Less: treasury stock, at cost; 2,246,069 and 2,147,724 common shares	-52	-48
Total Chesapeake Stockholders’ Equity	16,196	15,569
Noncontrolling interests	2,152	2,327
Total Equity	18,348	17,896
TOTAL LIABILITIES AND EQUITY	$42,288	$41,611

CONSOLIDATED_BALANCE_SHEETS_Pa

CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $)	Sep. 30, 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	667,472,869	666,467,664
Treasury stock, shares	2,246,069	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	-151	-58
Short-term derivative liabilities attributable to our VIEs	7	4
Other current liabilities attributable to our VIEs	24	21
Long-term derivative liabilities attributable to our VIEs	$1	$3

CONSOLIDATED_STATEMENTS_OF_OPE

CONSOLIDATED STATEMENTS OF OPERATIONS (USD $)	3 Months Ended		9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES:	'	'	'	'
Natural gas, oil and NGL	$1,586	$1,437	$5,444	$4,622
Marketing, gathering and compression	3,032	1,381	6,871	3,710
Oilfield services	249	152	650	446
Total Revenues	4,867	2,970	12,965	8,778
OPERATING EXPENSES:	'	'	'	'
Natural gas, oil and NGL production	282	320	877	1,005
Production taxes	62	53	173	141
Marketing, gathering and compression	3,009	1,339	6,781	3,631
Oilfield services	211	116	543	321
General and administrative	120	145	336	436
Restructuring Charges	63	3	203	4
Natural gas, oil and NGL depreciation, depletion and amortization	652	762	1,945	1,856
Depreciation and amortization of other assets	79	66	234	233
Impairment of natural gas and oil properties	0	3,315	0	3,315
Impairments of fixed assets and other	85	38	343	281
Net (gains) losses on sales of fixed assets	-132	7	-290	5
Total Operating Expenses	4,431	6,164	11,145	11,228
INCOME (LOSS) FROM OPERATIONS	436	-3,194	1,820	-2,450
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-40	-36	-164	-63
Losses on investments	-22	-23	-26	-87
Impairment of investment	0	0	-10	0
Gains (losses) on sales of investments	3	31	-7	1,061
Losses on purchases of debt	0	0	-70	0
Other income (expense)	10	-9	18	2
Total Other Income (Expense)	-49	-37	-259	913
INCOME (LOSS) BEFORE INCOME TAXES	387	-3,231	1,561	-1,537
INCOME TAX EXPENSE (BENEFIT):	'	'	'	'
Current income taxes	7	22	9	24
Deferred income taxes	140	-1,282	585	-623
Total Income Tax Expense (Benefit)	147	-1,260	594	-599
NET INCOME (LOSS)	240	-1,971	967	-938
Net income attributable to noncontrolling interests	-38	-41	-127	-131
NET INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	202	-2,012	840	-1,069
Preferred stock dividends	-43	-43	-128	-128
Premium on purchase of preferred shares of a subsidiary	0	0	-69	0
Earnings allocated to participating securities	-3	0	-14	0
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS	$156	($2,055)	$629	($1,197)
EARNINGS (LOSS) PER COMMON SHARE:	'	'	'	'
Basic	$0.24	($3.19)	$0.96	($1.86)
Diluted	$0.24	($3.19)	$0.96	($1.86)
CASH DIVIDEND DECLARED PER COMMON SHARE	$0.09	$0.09	$0.26	$0.26
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES OUTSTANDING (in millions):	'	'	'	'
Basic	656	644	654	643
Diluted	656	644	654	643

CONSOLIDATED_STATEMENTS_OF_COM

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Comprehensive Income [Abstract]	'	'	'	'
NET INCOME (LOSS)	$240	($1,971)	$967	($938)
OTHER COMPREHENSIVE INCOME (LOSS), NET OF INCOME TAX:	'	'	'	'
Unrealized gain on derivative instruments, net of income tax expense of $1 million, $1 million, $1 million and $1 million	2	3	2	3
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $1 million, ($3) million, $8 million and ($10) million	2	-6	13	-18
Unrealized loss on investments, net of income tax benefit of ($1) million, ($2) million, ($4) million and ($4) million	-1	-3	-6	-7
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of ($1) million, $0, $3 million and $0	-2	0	4	0
Other Comprehensive Income (Loss)	1	-6	13	-22
COMPREHENSIVE INCOME (LOSS)	241	-1,977	980	-960
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS	-38	-41	-127	-131
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	$203	($2,018)	$853	($1,091)

CONSOLIDATED_STATEMENTS_OF_COM1

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Unrealized gain on derivative instruments, net of income tax expense of $1 million, $1 million, $1 million and $1 million	$1	$1	$1	$1
Reclassification of (gain) loss on settled derivative instruments, net of income tax expense (benefit) of $1 million, ($3) million, $8 million and ($10) million	1	-3	8	-10
Unrealized loss on investments, net of income tax benefit of ($1) million, ($2) million, ($4) million and ($4) million	-1	-2	-4	-4
Reclassification of (gain) loss on investment, net of income tax expense (benefit) of ($1) million, $0, $3 million and $0	($1)	$0	$3	$0

CONSOLIDATED_STATEMENTS_OF_CAS

CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:	'	'
NET INCOME (LOSS)	$967	($938)
ADJUSTMENTS TO RECONCILE NET INCOME TO CASH PROVIDED BY OPERATING ACTIVITIES:	'	'
Depreciation, depletion and amortization	2,179	2,089
Deferred income tax expense (benefit)	585	-623
Derivative (income) expense	-90	-828
Cash (payments) receipts on derivative settlements, net	-91	388
Stock-based compensation	78	93
Net (gains) losses on sales of fixed assets	-290	6
Impairment of natural gas and oil properties	0	3,315
Impairments of fixed assets and other	317	256
Losses on investments	30	147
(Gains) losses on sales of investments	7	-1,061
Losses on purchases of debt	12	0
Impairment of investment	10	0
Restructuring and other termination benefits	164	4
Other	35	76
Changes in assets and liabilities	-352	-946
Net Cash Provided By Operating Activities	3,561	1,978
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Drilling and completion costs	-4,470	-7,525
Acquisitions of proved and unproved properties	-811	-2,813
Proceeds from divestitures of proved and unproved properties	2,789	2,445
Additions to other property and equipment	-639	-1,916
Proceeds from sales of other assets	796	219
Additions to investments	-8	-261
Proceeds from sales of investments	115	2,000
(Increase) decrease in restricted cash	177	-280
Other	4	-23
Net Cash Used In Investing Activities	-2,047	-8,154
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	7,136	13,986
Payments on credit facilities borrowings	-7,268	-13,614
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263
Proceeds from issuance of term loans, net of discount and offering costs	0	3,789
Cash paid to purchase debt	-2,116	0
Cash paid for common stock dividends	-175	-170
Cash paid for preferred stock dividends	-128	-128
Cash paid on financing derivatives	-62	-36
Cash paid for prepayment of mortgage	-55	0
Proceeds from sales of noncontrolling interests	5	1,056
Proceeds from other financings	22	225
Cash paid to purchase preferred shares of a subsidiary	-212	0
Distributions to noncontrolling interest owners	-164	-163
Other	-71	-227
Net Cash Provided By (Used In) Financing Activities	-814	5,981
Change in cash and cash equivalents classified as current assets held for sale	0	-14
Net increase (decrease) in cash and cash equivalents	700	-209
Cash and cash equivalents, beginning of period	287	351
Cash and cash equivalents, end of period	987	142
SUPPLEMENTAL CASH FLOW INFORMATION:	'	'
Interest, net of capitalized interest	62	0
Income taxes, net of refunds received	14	31
Change in accrued drilling and completion costs	-97	-103
Change in accrued acquisitions of proved and unproved properties	-1	60
Change in accrued additions to other property and equipment	($80)	$57

CONSOLIDATED_STATEMENTS_OF_STO

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (USD $)

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

In Millions, unless otherwise specified

Preferred Stock

Preferred Stock

Common Stock

Common Stock

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Paid-In Capital

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

Retained Earnings

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Treasury Stock - Common

Parent

Parent

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

Non-Controlling Interest

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Balance, beginning of period

$3,062

$3,062

$7

$7

'

'

$12,443

$12,293

$12,246

$12,146

'

'

$905

$437

$241

$1,608

'

'

($169)

($182)

($188)

($166)

'

'

($52)

($48)

($41)

($33)

$16,196

$15,327

'

'

$2,152

$2,327

$2,364

$1,337

Stock-based compensation

'

'

'

'

156

116

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Reduction in tax benefit from stock-based compensation

'

'

'

'

-10

-18

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Exercise of stock options

'

'

'

'

4

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net income (loss) attributable to Chesapeake

'

'

'

'

'

'

'

'

'

'

840

-1,069

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on common stock

'

'

'

'

'

'

'

'

'

'

-175

-170

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Dividends on preferred stock

'

'

'

'

'

'

'

'

'

'

-128

-128

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Premium on purchase of preferred shares of a subsidiary

'

'

'

'

'

'

'

'

'

'

-69

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Hedging activity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15

-15

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment activity

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-2

-7

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase of 249,498 and 357,565 shares for company benefit plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-6

-9

'

'

'

'

'

'

'

'

'

'

'

'

Release of 151,153 and 49,591 shares from company benefit plans

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

1

'

'

'

'

'

'

'

'

'

'

'

'

Sales of noncontrolling interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5

1,056

'

'

'

'

Net income attributable to noncontrolling interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

127

131

'

'

'

'

Distributions to noncontrolling interest owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-164

-160

'

'

'

'

Purchase of preferred shares of a subsidiary

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

-143

0

'

'

'

'

Balance, end of period

$3,062

$3,062

$7

$7

'

'

$12,443

$12,293

$12,246

$12,146

'

'

$905

$437

$241

$1,608

'

'

($169)

($182)

($188)

($166)

'

'

($52)

($48)

($41)

($33)

$16,196

$15,327

'

'

$2,152

$2,327

$2,364

$1,337

CONSOLIDATED_STATEMENTS_OF_STO1

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (Parenthetical) (Treasury Stock - Common)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
Treasury Stock - Common	'	'
Purchase of shares for company benefit plans, shares	249,498	357,565
Release of shares from company benefit plans, shares	151,153	49,591

Basis_of_Presentation_and_Summ

Basis of Presentation and Summary of Significant Accounting Policies (Note)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Basis of Presentation and Significant Accounting Policies [Text Block]	'
		Basis of Presentation and Summary of Significant Accounting Policies
	Principles of Consolidation
	The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation (“Chesapeake” or the “Company”) and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). This Form 10-Q relates to the three and nine months ended September 30, 2013 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2012 (the “Prior Quarter” and the “Prior Period”, respectively). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The accompanying condensed consolidated financial statements of Chesapeake include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake holds a controlling interest. All significant intercompany accounts and transactions have been eliminated. The results for the Current Quarter and Current Period are not necessarily indicative of the results to be expected for the full year.
	Critical Accounting Policies
	We consider accounting policies related to variable interest entities, natural gas and oil properties, derivatives and income taxes to be critical policies. These policies are summarized in Item 7 of our 2012 Form 10-K.
	Risks and Uncertainties
	Our primary business strategy over the last few years was to continue growing our reserves and production while transitioning from an asset base primarily focused on natural gas to an asset base more balanced between natural gas and liquids production. This was a capital-intensive strategy, and we made capital expenditures historically and in the Current Period that exceeded our cash flow from operations, supplementing such cash flows with borrowings, proceeds from strategic joint ventures and sales of assets that we determined were noncore or did not fit our long-term plans. The full year 2013 gap between forecasted capital expenditures and expected cash flow from operations is approximately $3.5 billion; however, this expected spending gap has been fully covered by joint venture and asset sales proceeds received year to date. We are working to execute our business with greater financial discipline and are targeting to balance capital expenditures with cash flow from operations over time. We expect to have the flexibility to fund any short-term disparities using our $4.0 billion corporate revolving credit facility, which was undrawn at September 30, 2013. As we apply available cash from future asset sales and operations towards reducing our financial leverage and complexity, we may incur various cash and noncash charges including but not limited to impairments of fixed assets, lease termination charges or financing extinguishment costs.
	We continue to have significant exposure to natural gas prices. Approximately 70% of our estimated proved reserve volumes as of December 31, 2012 were natural gas, and natural gas represented approximately 73% and 80% of our natural gas, oil and NGL sales volumes for the Current Quarter and the year ended December 31, 2012, respectively. To add more certainty to our future estimated cash flows, we currently have downside price protection, in the form of over-the-counter derivative contracts, on approximately 80% of our remaining 2013 estimated natural gas production at an average price of $3.69 per mcf and 91% of our remaining 2013 estimated oil production at an average price of $95.59 per bbl. We also have derivative contracts providing downside price protection in 2014 on 251 bcf of natural gas at an average price of $4.22 per mcf and 22 mmbbls of oil at an average price of $93.79 per bbl. While our use of derivative contracts allows us to reduce our exposure to price volatility on our cash flows and EBITDA (defined as earnings before interest, taxes, depreciation, depletion and amortization), the derivative contracts we elect to enter into for any period depend on our outlook on future prices and our risk assessment. Low natural gas, oil and NGL prices can reduce our estimate of proved reserves, potentially resulting in a future write-down of the carrying value of our natural gas and oil properties. In 2012, when natural gas prices reached 10-year lows, we reduced our estimate of proved reserves by 3.1 tcfe, or 17%, primarily due to the impact of downward natural gas price revisions, and we incurred a $3.3 billion write-down of the carrying value of our natural gas and oil properties. Future impairments of the carrying value of our natural gas and oil properties, if any, will be dependent on many factors, including natural gas, oil and NGL prices, production rates, levels of reserves, the evaluation of costs excluded from amortization, the timing and impact of asset sales, future development costs and service costs.
	Assets and Liabilities Held for Sale
	In the Current Period, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. In addition, as of September 30, 2013, we were continuing to pursue the sale of various land and buildings located in the Fort Worth, Texas area. The land and buildings in both the Oklahoma City and Fort Worth areas are reported under our other segment. We are also pursuing the sale of various other property and equipment, including certain drilling rigs, compressors and gathering systems. The drilling rigs are reported under our oilfield services operating segment and the compressors and gathering systems are reported under our marketing, gathering and compression operating segment. These assets are being actively marketed, and we believe it is probable they will be sold over the next 12 months. As a result, these assets qualified as held for sale as of September 30, 2013. Natural gas and oil properties that we intend to sell are not presented as held for sale pursuant to the rules governing full cost accounting for oil and gas properties. A summary of the assets and liabilities held for sale on our condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012 is detailed below.
			September 30,				December 31,
			2013				2012
			($ in millions)
	Accounts receivable		$	—			$	4
	Current assets held for sale		$	—			$	4
	Natural gas gathering systems and treating plants, net of accumulated depreciation		$	10			$	352
	Oilfield services equipment, net of accumulated depreciation		26				27
	Compressors, net of accumulated depreciation		242				—
	Buildings and land, net of accumulated depreciation		319				255
	Property and equipment held for sale, net		$	597			$	634
	Accounts payable		$	—			$	4
	Accrued liabilities		—				17
	Current liabilities held for sale		$	—			$	21
	Accumulated Other Comprehensive Income (Loss)
	For the Current Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
			Net Gains				Net Gains				Total
			(Losses) on				(Losses)
			Cash Flow				on
			Hedges				Investments
			($ in millions)
	Balance, December 31, 2012		$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications		2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income		13				4				17
	Net current period other comprehensive income		15				(2		)		13
	Balance, September 30, 2013		$	(174	)		$	5			$	(169	)
	For the Current Quarter and the Current Period, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed consolidated statement of operations are detailed below.
	Details About Accumulated		Affected Line Item		Three Months Ended				Nine Months Ended
	Other Comprehensive		in the Statement		30-Sep-13				30-Sep-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		$	2			$	13
	Investments:
	Impairment of investment		Impairment of investment		—				6
	Sale of investment		Gain on sale of investment		(2		)		(2		)
	Total reclassifications				$	—			$	17
	for the period, net of tax

Earnings_Per_Share_Note

Earnings Per Share (Note)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share, Basic and Diluted, Other Disclosures [Abstract]	'
Earnings Per Share Disclosure [Text Block]	'
	Earnings Per Share
	For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, our contingent convertible senior notes did not have a dilutive effect and therefore were excluded from the calculation of diluted earnings per share (EPS). See Note 3 for further discussion of our contingent convertible senior notes. Participating securities, for purposes of our EPS computations, consist of unvested restricted stock issued to our employees and non-employee directors that provide dividend rights.
	For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, the following shares of cumulative convertible preferred stock and unvested restricted stock 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:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	2
	Three Months Ended September 30, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	—	3
	Nine Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3
	Nine Months Ended September 30, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	—	4

Debt_Note

Debt (Note)	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Debt Disclosure [Text Block]	'
	Debt
	Our long-term debt consisted of the following as of September 30, 2013 and December 31, 2012:
			September 30, 2013				December 31, 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)		465				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		285				418
	Discount on senior notes and term loan(d)		(380		)		(465		)
	Interest rate derivatives(e)		14				20
	Total debt, net		12,736				12,620
	Less current maturities of long-term debt, net(f)		—				(463		)
	Total long-term debt, net		$	12,736			$	12,157
	___________________________________________
	(a)	The principal amount shown is based on the exchange rate of $1.3527 to €1.00 and $1.3193 to €1.00 as of September 30, 2013 and December 31, 2012, respectively. See Note 7 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 Current Quarter, 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 fourth quarter of 2013 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. During the Current Quarter, the notes were not convertible under this provision. 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		$	48.31			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		$	107.01			June 14, 2019
	(d)	Discount as of September 30, 2013 and December 31, 2012 included $322 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. The discount also included $34 million and $40 million as of September 30, 2013 and December 31, 2012, respectively, associated with our term loan discussed further below.
	(e)	See Note 7 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.
	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 at a make-whole price in the first year, at par plus a specified premium in the second and third years 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 September 30, 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.
	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 wholly owned subsidiaries. See Note 16 for condensed consolidating financial information regarding our guarantor and non-guarantor subsidiaries.
	We may redeem the senior notes, other than the contingent convertible senior notes, at any time at specified make-whole or redemption prices. Our senior notes are governed by indentures containing covenants that may limit our ability and our subsidiaries’ ability to incur certain secured indebtedness, enter into sale/leaseback transactions, and consolidate, merge or transfer assets. The indentures governing the senior notes and the contingent convertible senior notes do not have any financial or restricted payment covenants. The senior notes and contingent convertible senior notes indentures have cross default provisions that apply to other indebtedness the Company or any guarantor subsidiary may have from time to time with an outstanding principal amount of at least $50 million, depending on the indenture.
	We are required to account for the liability and equity components of our convertible debt instruments separately and to reflect interest expense at the interest rate of similar nonconvertible debt at the time of issuance. The applicable rates for our 2.75% Contingent Convertible Senior Notes due 2035, our 2.5% Contingent Convertible Senior Notes due 2037 and our 2.25% Contingent Convertible Senior Notes due 2038 are 6.86%, 8.0% and 8.0%, respectively.
	During the Current Period, 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 purchase certain senior notes. We purchased $217 million in aggregate principal amount of our 7.625% Senior Notes due 2013 for $221 million and $377 million in aggregate principal amount of our 6.875% Senior Notes due 2018 for $405 million pursuant to tender offers which expired on April 12, 2013. 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 Current Quarter, we retired at maturity the remaining $247 million aggregate principal amount outstanding of our 7.625% Senior Notes due 2013.
	During the Prior Period, 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 recent 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 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 $50 million or more.
	Under a registration rights agreement, we agreed to file a registration statement enabling holders of the COO senior notes to exchange the privately placed COO senior notes for publicly registered notes with substantially the same terms. The exchange offer was completed on July 19, 2013.
	Bank Credit Facilities
	During the Current Period, we had two revolving bank credit facilities as sources of liquidity. In addition, in the Prior Period, we had a midstream credit facility. In June 2012, we paid off and terminated our midstream credit facility. Our remaining revolving bank credit facilities are described below.
			Corporate				Oilfield Services
			Credit Facility(a)				Credit Facility(b)
			($ 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 September 30, 2013		$	—			$	285
Letters of credit outstanding as of September 30, 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.
Our credit facilities do not contain material adverse change or adequate assurance covenants. Although the applicable interest rates under our corporate credit facility fluctuate slightly 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 September 30, 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 September 30, 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)	9 Months Ended
	Sep. 30, 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 individual defendants are not required to answer the complaint unless and until the plaintiff establishes standing to pursue claims derivatively.
	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 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. 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. Two additional related state court derivative actions were appealed to the Oklahoma Supreme Court, one on May 31, 2013 and the other on June 20, 2013. In both cases, the District Court of Oklahoma County, Oklahoma had granted Chesapeake's motion to dismiss for lack of derivative standing.
	In June and July 2012, three putative class actions were filed in the U.S. District Court for the Western District of Oklahoma against the Company, Chesapeake Energy Savings and Incentive Stock Bonus Plan (the Plan), and certain of the Company’s officers and directors alleging breaches of fiduciary duties under the Employee Retirement Income Security Act (ERISA). The three cases have been consolidated, and the Plan was not named in the consolidated amended complaint which was filed on February 21, 2013. The action was brought on behalf of participants and beneficiaries of the Plan and alleged that, as fiduciaries of the Plan, defendants owed fiduciary duties, which they purportedly breached by, among other things, failing to manage and administer the Plan’s assets with appropriate skill and care and engaging in activities that were in conflict with the best interest of the Plan. The plaintiffs sought class certification, damages of an unspecified amount, equitable relief, and attorneys’ fees and other costs. The defendants filed a motion to dismiss on April 22, 2013, which was granted on October 11, 2013. We are currently unable to assess the probability of loss or estimate a range of potential loss associated with this matter.
	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 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 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. Chesapeake has engaged in discussions with the DOJ and state agencies and continues to respond to such subpoenas and demands, including the subpoena issued by the DOJ’s Antitrust Division, Midwest Field Office on June 29, 2012 relating to an investigation into possible violations of antitrust laws being conducted by a grand jury in the Western District of Michigan and a subpoena issued by the Michigan Department of Attorney General on September 16, 2013 relating to its investigation of possible violations of that state’s criminal solicitation law. Chesapeake’s Board of Directors commenced in June 2012 its own investigation of certain conduct covered by the DOJ subpoena, and in February 2013, the Company announced the Board’s conclusion that the Company did not violate antitrust laws in connection with the acquisition of Michigan oil and gas rights in 2010.
	Business Operations. Chesapeake is involved in various other lawsuits and disputes incidental to its business operations, including commercial disputes, personal injury claims, royalty claims, property damage claims and contract actions. With regard to contract actions, various mineral or leasehold owners have filed lawsuits against us seeking specific performance to require us to acquire their natural gas and oil interests and pay acreage bonus payments, damages based on breach of contract and/or, in certain cases, punitive damages based on alleged fraud. The Company has successfully defended a number of these cases in various courts, has settled others and believes that it has substantial defenses to the claims made in those pending at the trial court and on appeal. Regarding royalty claims, Chesapeake and other natural gas producers have been named in various lawsuits alleging royalty underpayment. The suits allege that we used below-market prices, made improper deductions, used improper measurement techniques and/or entered into arrangements with affiliates that resulted in underpayment of royalties in connection with the production and sale of natural gas and NGL. The Company is defending against certain pending claims, has resolved a number of claims through negotiated settlements of past and future royalties and has prevailed in various other lawsuits.
	Based on management’s current assessment, we are of the opinion that no pending or threatened lawsuit or dispute relating to the Company’s business operations is likely to have a material adverse effect on its consolidated financial position, results of operations or cash flows. The final resolution of such matters could exceed amounts accrued, however, and actual results could differ materially from management’s estimates.
	Environmental Risk
	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.
	There are presently pending against our subsidiary, Chesapeake Appalachia, L.L.C. (CALLC), orders for compliance first initiated in the 2010 fourth quarter by the U.S. Environmental Protection Agency (EPA) related to our compliance with Clean Water Act (CWA) permitting requirements in West Virginia. We have responded to all pending orders and are actively working with the EPA to resolve these and similar matters. We expect that resolution of pending EPA matters will include monetary sanctions exceeding $100,000, but we believe any associated liability will not have a material effect on the consolidated financial position, results of operations or cash flow of the Company.
	For one West Virginia site that was subject to an EPA order for compliance, CALLC pled guilty on December 3, 2012 to three misdemeanor counts of unauthorized discharge of dredged or fill materials into a water of the U.S. We have paid the applicable fine in full, our restoration of the site has been completed and approved by the government, and we believe that CALLC is in compliance with the terms of probation. By operation of law, a CWA conviction triggers “disqualification”, by which the disqualified entity is prohibited from receiving federal contracts or benefits until the EPA certifies that the conditions giving rise to the conviction have been corrected. Disqualification of CALLC has not had, and we do not expect it to have, a material adverse impact on our business.
	Commitments
	Rig Leases
	In a series of transactions beginning in 2006, our drilling subsidiary sold 94 drilling rigs (of which 28 rigs have been repurchased) and related equipment and entered into master lease agreements under which we agreed to lease the rigs from the buyer for initial terms of five to ten years. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks and any related net gains are amortized to oilfield services expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the rigs at the expiration of the lease for the fair market value at the time. In addition, in most cases, we have the option to renew a lease for negotiated new terms at the expiration of the lease. Commitments related to rig lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2013, the minimum aggregate undiscounted future rig lease payments were approximately $239 million. Subsequent to September 30, 2013, we repurchased nine rigs for approximately $70 million from lessors, lowering our minimum aggregate undiscounted future rig lease payments by approximately $58 million. See Note 18 for further discussion of the repurchases.
	Chesapeake has contracts with various drilling contractors to utilize approximately 11 rigs with terms ranging from one to three years. These commitments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2013, the aggregate undiscounted minimum future payments under these drilling rig commitments were approximately $82 million.
	Compressor Leases
	Through various transactions beginning in 2007, our compression subsidiary sold 2,558 compressors (of which 250 units have been repurchased), a significant portion of its compressor fleet, and entered into a master lease agreement under which we agreed to lease the compressors from the buyer for initial terms of four to ten years. The lease commitments are guaranteed by Chesapeake and certain of its subsidiaries. These transactions were recorded as sales and operating leasebacks, and any related net gains are amortized to marketing, gathering and compression expenses over the lease term. Under the leases, we can exercise an early purchase option or we can purchase the compressors at the expiration of the lease for the fair market value at the time. In addition, in most cases we have the option to renew a lease for negotiated new terms at the expiration of the lease. Commitments related to compressor lease payments are not recorded in the accompanying condensed consolidated balance sheets. As of September 30, 2013, the minimum aggregate undiscounted future compressor lease payments were approximately $348 million.
	Gathering, Processing and Transportation Agreements
	We have contractual commitments with midstream service companies and pipeline carriers for future gathering, processing and transportation of natural gas and liquids to move certain of our production to market. Working interest owners and royalty interest owners, where appropriate, will be responsible for their proportionate share of these costs. Commitments related to gathering, processing and transportation agreements are not recorded in the accompanying condensed consolidated balance sheets; however, they are reflected as adjustments to future natural gas, oil and NGL sales prices used in our proved reserves estimates.
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, are presented below.
		September 30, 2013
		($ in millions)
	2013	$	510
	2014	2,010
	2015	1,821
	2016	1,910
	2017	1,942
	2018 - 2099	9,546
	Total	$	17,739
	Drilling Commitments
	In December 2011, as part of our Utica joint venture development agreement with Total S.A. (Total) (see Note 8), 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 September 30, 2013, we had spud 357 cumulative Utica wells and had met our 2012 and 2013 commitments. If we fail to meet the drilling commitment at July 31, 2015 for any reason other than a force majeure event, the drilling carry percentage used to determine our promoted well reimbursement will be reduced from 60% to 45% for the number of wells drilled in the subsequent 12-month period represented by the shortfall versus our drilling commitment. As such, any reduction would only affect the timing of the receipt of the drilling carry but not the total drilling carry to be received.
	We have also committed to drill wells in conjunction with our CHK Utica and CHK C-T financial transactions and in conjunction with the formation of the Chesapeake Granite Wash Trust. See Note 6 for discussion of these transactions and commitments.
	Property and Equipment Purchase Commitments
	Much of the oilfield services and other equipment we purchase requires long production lead times. As a result, we have outstanding orders and commitments for such equipment. As of September 30, 2013, we had $50 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 8 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 8), 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 did not fully meet the initial 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 condensed consolidated statements of operations for an estimated shortfall of approximately 13,000 net acres. As of September 30, 2013, we revised our estimate of the net acreage shortfall as of December 31, 2012 to be approximately 14,000 net acres and anticipate making a cash payment of approximately $28 million to Total in the 2013 fourth quarter. Total has disputed our estimate of the shortfall, however, and the final resolution of this matter could exceed amounts we have accrued for maintenance of Total’s acreage position.
	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 under certain agreements between us and our non-guarantor subsidiaries could affect our EBITDA or indebtedness for purposes of our credit facility covenant calculations, but they would have no effect on the condensed 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 September 30, 2013, we had accrued a nominal amount for non-utilization pursuant to the agreement and eliminated its impact in consolidation. Any monetary penalties incurred in future periods would also be eliminated 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 entered into any backstop contracts.
	In July 2011, we agreed to invest $155 million in preferred equity securities of Sundrop Fuels, Inc., a privately held cellulosic biofuels company based in Longmont, Colorado. As of September 30, 2013, we had funded $115 million of our commitment. The remaining tranches of preferred equity investment will be scheduled around certain funding and operational milestones that are expected to be reached in the 2014 first quarter. See Note 9 for further discussion of this investment.
	In December 2011, we sold Appalachia Midstream Services, L.L.C., a wholly owned subsidiary of our wholly owned subsidiary, Chesapeake Midstream Development, L.L.C. (CMD), to Access Midstream Partners, L.P. (NYSE:ACMP) for total consideration of $884 million. In addition, CMD committed to pay ACMP for any quarterly shortfall between the actual adjusted EBITDA from the assets sold and specified quarterly targets totaling $100 million in 2012 and $150 million in 2013. We recorded this guarantee at an estimated fair value of $27 million at the time of the sale. No payment was required for the Current Period or for 2012, and we recognized an $11 million gain in the Current Period associated with the release of this guarantee. The remaining $8 million fair value is included in other current liabilities on our condensed consolidated balance sheet as of September 30, 2013. We will release this liability in the 2013 fourth quarter if CMD is not required to make a payment under the guarantee. If payment is required, we will record the difference between the liability and the associated payment in earnings.
	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 8 for further discussion of our VPP transactions.

Other_Liabilities_Note

Other Liabilities (Note)	9 Months Ended
	Sep. 30, 2013
Other Liabilities Disclosure [Abstract]	'
Other Liabilities Disclosure [Text Block]	'
	Other Liabilities
	Other current liabilities as of September 30, 2013 and December 31, 2012 are detailed below.
			September 30, 2013		December 31, 2012
			($ in millions)
	Revenues and royalties due others		$	1,621	$	1,337
	Accrued natural gas, oil and NGL drilling and production costs		417		525
	Joint interest prepayments received		472		749
	Accrued compensation and benefits		276		225
	Other accrued taxes		178		130
	Accrued dividends		102		101
	Other		559		674
	Total other current liabilities		$	3,625	$	3,741
	Other long-term liabilities as of September 30, 2013 and December 31, 2012 are detailed below.
			September 30, 2013		December 31, 2012
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	256	$	275
	CHK C-T ORRI conveyance obligation(b)		153		164
	Financing obligations(c)		191		175
	Mortgages payable(d)		—		56
	Other		580		506
	Total other long-term liabilities		$	1,180	$	1,176
	____________________________________________
	(a)	$23 million and $18 million of the total $279 million and $293 million obligations are recorded in other current liabilities as of September 30, 2013 and December 31, 2012, respectively. See Note 6 for further discussion of the transaction.
	(b)	$10 million and $14 million of the total $163 million and $178 million obligations are recorded in other current liabilities as of September 30, 2013 and December 31, 2012, respectively. See Note 6 for further discussion of the transaction.
	(c)	Consists primarily of an obligation related to 111 real estate surface properties in the Fort Worth area that we financed in 2009 for approximately $145 million and we entered into a 40-year master lease agreement under which 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 condensed consolidated balance sheet. Chesapeake exercised its option to repurchase one of the properties in 2011 and four of the properties in the Current Period. See Note 18 for a discussion of the termination of this lease agreement on November 1, 2013.
	(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 the Current Period, we prepaid the term loan in full without penalty. As of September 30, 2013, the building was classified as property and equipment held for sale on our condensed consolidated balance sheet.

Stockholders_Equity_StockBased

Stockholders' Equity, Stock-Based Compensation, Performance Share Units and Noncontrolling Interests (Note)	9 Months Ended
	Sep. 30, 2013
Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest [Abstract]	'
Stockholders' Equity, Stock-Based Compensation, Performance Share Units and Noncontrolling Interests Disclosure [Text Block]	'
	Stockholders’ Equity, Stock-Based Compensation, Performance Share Units and Noncontrolling Interests
	Common Stock
	The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2013 and 2012:
			Nine Months Ended
			September 30,
			2013			2012
			(in thousands)
	Shares issued as of January 1		666,468			660,888
	Restricted stock issuances (net of forfeitures)(a)		684			5,758
	Stock option exercises		321			309
	Shares issued as of September 30		667,473			666,955
	___________________________________________
	(a)	In June 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors, and in the Current Quarter, we began granting RSUs in lieu of RSAs to employees. Shares of common stock underlying RSUs are issued when the units vest, whereas restricted shares of common stock are issued on the grant date of RSAs. We refer to RSAs and RSUs collectively as restricted stock.
	Preferred Stock
	The following reflects the shares outstanding and liquidation preference of our preferred shares for the nine months ended September 30, 2013 and 2012:
			5.75%				5.75% (A)				4.50%				5.00%		Total
															(2005B)
	Shares outstanding as of January 1, 2013		1,497				1,100				2,559				2,096		7,252
	and 2012 and September 30, 2013 and 2012
	(in thousands)
	Liquidation preference per share		$	1,000			$	1,000			$	100			$	100
	Dividends
	Dividends declared on our common stock and preferred stock are reflected as adjustments to retained earnings to the extent a surplus of retained earnings will exist after giving effect to the dividends. To the extent retained earnings are insufficient to fund the distributions, such payments constitute a return of contributed capital rather than earnings and are accounted for as a reduction to paid-in capital.
	Dividends on our outstanding preferred stock are payable quarterly. We may pay dividends on our 5.00% Cumulative Convertible Preferred Stock (Series 2005B) and our 4.50% Cumulative Convertible Preferred Stock in cash, common stock or a combination thereof, at our option. Dividends on both series of our 5.75% Cumulative Convertible Non-Voting Preferred Stock are payable only in cash.
	Stock-Based Compensation
	Chesapeake’s stock-based compensation program consists of restricted stock and stock options 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 awards of equity instruments, including restricted stock and stock options, based on the fair value of the equity instruments at the date of the grant. For employees, this value is amortized over the vesting period, which is generally three or four years from the date of grant. For directors, although restricted stock grants vest over three years, this value is expensed immediately as there is a non-substantive service condition for vesting. 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. We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2013				2012				2013				2012
			($ in millions)
	Natural gas and oil properties		$	12			$	18			$	45			$	55
	General and administrative expenses		13				17				48				55
	Natural gas, oil and NGL production expenses		5				6				17				18
	Marketing, gathering and compression expenses		2				4				5				12
	Oilfield services expenses		3				2				8				8
	Total		$	35			$	47			$	123			$	148
	Restricted Stock
	In the Current Period, we granted 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 during the nine months ended September 30, 2013 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		9,053			$	19.44
	Vested		(9,553	)		$	23.31
	Forfeited		(1,353	)		$	21.61
	Unvested shares as of September 30, 2013		17,046			$	21.85
	The aggregate intrinsic value of restricted stock that vested during the Current Period was approximately $187 million based on the stock price at the time of vesting.
	As of September 30, 2013, there was $244 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 2.6 years.
	The vesting of certain restricted stock grants could result in state and federal income tax benefits related to the difference between the market price of the common stock at the date of vesting and the date of grant. During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized reductions in tax benefits related to restricted stock of a nominal amount, $14 million, $12 million and $19 million, respectively, which were recorded as adjustments to additional paid-in capital and deferred income taxes.
	Stock Options
	In the Current Period, we granted members of our senior management team stock options that will vest ratably over a three-year period. We also granted retention awards to certain officers of stock options that will vest one-third on each of the third, fourth and fifth anniversaries of the grant date. The stock option awards have an exercise price equal to the closing price of the Company’s common stock on the grant date. Prior to 2006, we had granted stock options under several stock compensation plans which vested over a four-year period. Outstanding options expire ten years from the date of grant.
	The following table provides information related to stock option activity for the nine months ended September 30, 2013:
			Number of			Weighted				Weighted		Aggregate
			Shares			Average				Average		Intrinsic
			Underlying			Exercise				Contract		Value(a)
			Options			Price				Life in
						Per Share				Years
			(in thousands)									($ in millions)
	Outstanding at January 1, 2013		481			$	12.69			0.96		$	2
	Granted		5,264			$	19.32
	Exercised		(345	)		$	10.81
	Expired		(94	)		$	19.43
Outstanding at September 30, 2013		5,306			$	19.27			7.18		$	35
Exercisable at September 30, 2013		1,386			$	18.79			2.34		$	10
___________________________________________
(a)	The intrinsic value of a stock option is the amount by which the current market value or the market value upon exercise of the underlying stock exceeds the exercise price of the option.
As of September 30, 2013, there was $19 million of total unrecognized compensation cost related to stock options. The cost is expected to be recognized over a weighted average period of approximately 2.8 years.
During the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, we recognized excess tax benefits related to stock options of $2 million, a nominal amount, $2 million and $1 million, respectively. All amounts were recorded as adjustments to additional paid-in capital and deferred income taxes.
Performance Share Units
In January 2012 and 2013, we granted performance share units (PSUs) to senior management under our Long Term Incentive Plan that vest ratably over a three-year period. The 2012 awards are settled in cash on the first, second and third anniversary dates of the awards, and the 2013 awards are settled in cash on the third anniversary of the awards. The PSU awards include both an internal operational performance condition and an external market condition. The operational performance condition is a function of internal proved reserves growth and production growth. The market condition is a function of total shareholder return (TSR), and generally requires a Monte Carlo simulation to determine the fair value.
For PSUs granted in 2012, each of the TSR and operational payout components can range from 0% to 125% resulting in a maximum total payout of 250%. For PSUs granted in 2013, the TSR component can range from 0% to 125% and each of the two operational components can range from 0% to 62.5%; however, the maximum total payout is capped at 200% in all cases and at 100% in situations where the Company’s absolute TSR is less than zero. The PSUs can only be settled in cash, so they are classified as a liability in our condensed consolidated financial statements and are measured at fair value as of the grant date and re-measured at fair value at the end of each reporting period. This fair value adjustment is recognized as compensation expense in the condensed consolidated statements of operations.
The following table presents a summary of our PSU awards as of September 30, 2013:
		Units			Fair Value				Fair Value				Liability for
					as of								Vested
					Grant-Date								Amount
					($ in millions)
2012 Awards (a)
Payable 2014		278,084			$	8			$	10			$	10
Payable 2015		834,246			23				29				28
Total 2012 Awards		1,112,330			$	31			$	39			$	38
2013 Awards
Payable 2016		1,637,601			$	37			$	54			$	40
___________________________________________
(a)	In the Current Period, we paid $2 million related to 2012 PSU awards.
Noncontrolling Interests
Cleveland Tonkawa Financial Transaction. We formed CHK Cleveland Tonkawa, L.L.C. (CHK C-T) in March 2012 to continue development of a portion of our natural gas and oil assets in our Cleveland and Tonkawa plays. CHK C-T is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK C-T, we contributed to CHK C-T approximately 245,000 net acres of leasehold and the existing wells within an area of mutual interest in the plays between the top of the Tonkawa and the top of the Big Lime formations covering Ellis and Roger Mills counties in western Oklahoma. In March 2012, in a private placement, third-party investors contributed $1.25 billion in cash to CHK C-T in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3.75% overriding royalty interest (ORRI) in the existing wells and up to 1,000 future net wells to be drilled on the contributed play leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK C-T limited liability company agreement (the CHK C-T LLC Agreement), as the holder of all the common shares and the sole managing member of CHK C-T, we maintain voting and managerial control of CHK C-T and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $225 million to the ORRI obligation and $1.025 billion to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheets. Pursuant to the CHK C-T LLC Agreement, CHK C-T is currently required to retain an amount of cash (measured quarterly) equal to (i) the next two quarters of preferred dividend payments plus (ii) its projected operating funding shortfall for the next six months (projected operating funding shortfall requirement ends on December 31, 2013). The amount so retained, approximately $38 million as of September 30, 2013, is reflected as restricted cash on our condensed consolidated balance sheet.
Dividends on the preferred shares are payable on a quarterly basis at a rate of 6% per annum based on $1,000 per share. This dividend rate is subject to increase in limited circumstances in the event that, and only for so long as, any dividend amount is not paid in full for any quarter. As the managing member of CHK C-T, we may, at our sole discretion and election at any time after March 31, 2014, distribute certain excess cash of CHK C-T, as determined in accordance with the CHK C-T LLC Agreement. Any such optional distribution of excess cash is allocated 75% to the preferred shares (which is applied toward redemption of the preferred shares) and 25% to the common shares unless we have not met our drilling commitment at such time, in which case an optional distribution would be allocated 100% to the preferred shares (and applied toward redemption thereof). We may also, at our sole discretion and election, in accordance with the CHK C-T LLC Agreement, cause CHK C-T to redeem all or a portion of the CHK C-T preferred shares for cash. The preferred shares may be redeemed at a valuation equal to the greater of a 9% internal rate of return or a return on investment of 1.35x, in each case inclusive of dividends paid through redemption at the rate of 6% per annum and optional distributions made through the applicable redemption date. In the event that redemption does not occur on or prior to March 31, 2019, the optional redemption valuation will increase to provide a 15% internal rate of return to the investors. The preferred shares can be redeemed on a pro-rata basis in accordance with the then-applicable redemption valuation formula. As of September 30, 2013, the redemption price and the liquidation preference were each $1,260 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 73 and 58 qualified net wells were added in the Current Period and the Prior Period, respectively. As of September 30, 2013, we had met our 2013 drilling commitment 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 80 net wells in the Current Period and 50 net wells in the Prior Period. 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 September 30, 2013, we were on target to meet the 2013 ORRI conveyance commitment associated with the CHK C-T transaction.
As of September 30, 2013 and December 31, 2012, $1.015 billion of noncontrolling interests on our condensed consolidated balance sheets was attributable to CHK C-T. In the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of $19 million, $19 million, $56 million and $38 million, respectively, was attributable to the noncontrolling interests of CHK C-T.
Utica Financial Transaction. We formed CHK Utica, L.L.C. (CHK Utica) in October 2011 to develop a portion of our Utica Shale natural gas and oil assets. CHK Utica is an unrestricted subsidiary under our corporate credit facility agreement and is not a guarantor of, or otherwise liable for, any of our indebtedness or other liabilities, including indebtedness under our indentures. In exchange for all of the common shares of CHK Utica, we contributed to CHK Utica approximately 700,000 net acres of leasehold and the existing wells within an area of mutual interest in the Utica Shale play covering 13 counties located primarily in eastern Ohio. During November and December 2011, in private placements, third-party investors contributed $1.25 billion in cash to CHK Utica in exchange for (i) 1.25 million preferred shares, and (ii) our obligation to deliver a 3% ORRI in 1,500 net wells to be drilled on certain of our Utica Shale leasehold. Subject to customary minority interest protections afforded the investors by the terms of the CHK Utica limited liability company agreement (the CHK Utica LLC Agreement), as the holder of all the common shares and the sole managing member of CHK Utica, we maintain voting and managerial control of CHK Utica and therefore include it in our condensed consolidated financial statements. Of the $1.25 billion of investment proceeds, we allocated $300 million to the ORRI obligation and $950 million to the preferred shares based on estimates of fair values. The remaining ORRI obligation is included in other current and long-term liabilities and the preferred shares are included in noncontrolling interests on our condensed consolidated balance sheets. Pursuant to the CHK Utica LLC Agreement, CHK Utica is required to retain a cash balance equal to the next two quarters of preferred dividend payments. The amount reserved for paying such dividends, approximately $37 million, was reflected as restricted cash on our condensed consolidated balance sheet as of September 30, 2013. 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, we held $155 million received from divestitures defined by the agreement as restricted cash in other long-term assets on our condensed consolidated balance sheet. In the Current Period, we used all of the $155 million 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 September 30, 2013, the redemption price and the liquidation preference were each approximately $1,270 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 8 for further discussion of the joint venture. Under the development agreement, approximately 86 and 40 qualified net wells were added in the Current Period and Prior Period, respectively. As of September 30, 2013, we had met our 2013 drilling commitment 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 100 new net wells in the Current Period and 31 net wells in the Prior Period. 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 September 30, 2013, we were on target to meet the 2013 ORRI conveyance commitment associated with the CHK Utica transaction.
As of September 30, 2013 and December 31, 2012, $807 million and $950 million of noncontrolling interests on our condensed consolidated balance sheets, respectively, were attributable to CHK Utica. For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, income of approximately $18 million, $22 million, $60 million and $66 million, respectively, was attributable to the noncontrolling interests of CHK Utica. In the Current Period, 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 September 30, 2013, we had drilled or caused to be drilled approximately 80 development wells, as calculated under the development agreement, and the maximum amount recoverable under the drilling support lien was approximately $85 million.
The subordinated units we hold in the Trust are entitled to receive pro rata distributions from the Trust each quarter if and to the extent there is sufficient cash to provide a cash distribution on the common units that is not less than the applicable subordination threshold for 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. In exchange for agreeing to subordinate a portion of our Trust units, and in order to provide additional financial incentive to us to satisfy our drilling obligation and perform operations on the underlying properties in an efficient and cost-effective manner, Chesapeake is entitled to receive incentive distributions equal to 50% of the amount by which the cash available for distribution on the Trust units in any quarter exceeds the applicable incentive threshold for such quarter. The remaining 50% of cash available for distribution in excess of the applicable incentive threshold will be paid to Trust unitholders, including Chesapeake, on a pro rata basis. At the end of the fourth full calendar quarter following our satisfaction of our drilling obligation with respect to the development wells, the subordinated units will automatically convert into common units on a one-for-one basis and our right to receive incentive distributions will terminate. After such time, the common units will no longer have the protection of the subordination threshold, and all Trust unitholders will share in the Trust’s distributions on a pro rata basis.
For the Current Period and Prior Period, the Trust declared and paid the following distributions:
Production Period		Distribution Date		Cash Distribution				Cash Distribution
				per				per
				Common Unit				Subordinated Unit
March 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
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 condensed consolidated financial statements. As of September 30, 2013 and December 31, 2012, $323 million and $356 million of noncontrolling interests on our condensed consolidated balance sheets, respectively, were attributable to the Trust. For the Current Quarter, Prior Quarter, Current Period and Prior Period, income of approximately $2 million, $1 million, $14 million and $28 million, respectively, was attributable to the Trust’s noncontrolling interests in our condensed consolidated statements of operations. See Note 10 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 eventual 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 September 30, 2013 and December 31, 2012, $7 million and $5 million of noncontrolling interests on our condensed consolidated balance sheets, respectively, were attributable to Wireless. In the Current Quarter and Current Period, losses of $1 million and $3 million, respectively, were attributable to noncontrolling interests of Wireless in our condensed consolidated statement of operations.

Derivative_and_Hedging_Activit

Derivative and Hedging Activities (Note)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative and Hedging Activities Disclosure [Text Block]	'
		Derivative and Hedging Activities
	Natural Gas, Oil and NGL Derivatives
	Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL. To mitigate a portion of our exposure to adverse price changes, we have entered into various derivative instruments. These instruments allow us to predict with greater certainty the effective prices to be received for our production. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives. As of September 30, 2013 and December 31, 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.
	•	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.
	•	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 price, 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 collar. This eliminates the counterparty’s downside exposure below the second put option strike price.
	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.
	The estimated fair values of our natural gas and oil derivative instrument assets (liabilities) as of September 30, 2013 and December 31, 2012 are provided below.
			30-Sep-13							31-Dec-12
			Volume			Fair Value				Volume			Fair Value
						($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps		341			$	96			49			$	24
	Call options		193			(219		)		193			(240		)
	Call swaptions		12			—				—			—
	Basis protection swaps		79			(2		)		111			(15		)
	Three-way collars		36			4				—			—
	Total natural gas		661			(121		)		353			(231		)
	Oil (mmbbl):
	Fixed-price swaps		31.6			(94		)		28.1			68
	Call options		65.6			(368		)		73.8			(748		)
	Call swaptions		5.3			(1		)		5.3			(13		)
	Basis protection swaps		0.5			1				5.5			—
	Total oil		103			(462		)		112.7			(693		)
	Total estimated fair value					$	(583	)					$	(924	)
	Pursuant to accounting guidance, certain derivatives qualify for designation as cash flow hedges. Following this guidance, changes in the fair value of derivative instruments designated as cash flow hedges, to the extent they are effective in offsetting cash flows attributable to the hedged risk and locked-in gains and losses of settled designated derivative contracts, are recorded in accumulated other comprehensive income until the hedged item is recognized in earnings. Any change in fair value resulting from ineffectiveness is recognized in natural gas, oil and NGL sales. Changes in the fair value of derivatives not designated as cash flow hedges that occur prior to their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within natural gas, oil and NGL sales. As of September 30, 2013, we did not have any natural gas or oil derivatives that were designated as cash flow hedges. Therefore, changes in the fair value of these derivatives are reported in the condensed consolidated statement of operations. See further discussion below under Cash Flow Hedges.
	The components of natural gas, oil and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2013				2012				2013				2012
			($ in millions)
	Natural gas, oil and NGL sales		$	1,839			$	1,464			$	5,303			$	3,798
	Gains (losses) on natural gas, oil and NGL derivatives		(253		)		(27		)		141				824
	Total natural gas, oil and NGL sales		$	1,586			$	1,437			$	5,444			$	4,622
	Hedging Facility
	We have a multi-counterparty secured hedging facility with 16 counterparties that have committed to provide approximately 6.4 tcfe of hedging capacity for natural gas, oil and NGL price derivatives and 6.4 tcfe for basis derivatives with an aggregate mark-to-market capacity of $17.0 billion under the terms of the facility. As of September 30, 2013, we had hedged under the facility 1.2 tcfe of our future production with price derivatives and 0.1 tcfe 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 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.
	Interest Rate Derivatives
	To mitigate a portion of our exposure to volatility in interest rates related to our senior notes and bank credit facilities, we enter into interest rate derivatives. As of September 30, 2013 and December 31, 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 September 30, 2013 and December 31, 2012 are provided below.
			30-Sep-13								31-Dec-12
			Notional				Fair				Notional				Fair
			Amount				Value				Amount				Value
							($ in millions)
	Interest rate swaps		$	2,500			$	(88	)		$	1,050			$	(35	)
	Realized and unrealized gains or losses from interest rate derivative transactions are reflected as adjustments to interest expense in the condensed consolidated statements of operations. The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2013				2012				2013				2012
			($ in millions)
	Interest expense on senior notes		$	180			$	187			$	560			$	546
	Interest expense on credit facilities		8				13				30				51
	Interest expense on term loans		29				112				87				173
	(Gains) losses on interest rate derivatives		(3		)		(2		)		51				(4		)
	Amortization of loan discount, issuance costs and other		21				24				70				67
	Capitalized interest		(195		)		(298		)		(634		)		(770		)
	Total interest expense		$	40			$	36			$	164			$	63
	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 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 condensed consolidated balance sheet as a liability of $5 million as of September 30, 2013. The euro-denominated debt in long-term debt has been adjusted to $465 million as of September 30, 2013 using an exchange rate of $1.3527 to €1.00.
	Additional Disclosures Regarding Derivative Instruments and Hedging Activities
	In accordance with accounting guidance for derivatives and hedging, to the extent that a legal right of set-off exists, we net the value of our derivative arrangements with the same counterparty in the accompanying condensed consolidated balance sheets. Derivative instruments reflected as current in the condensed consolidated balance sheets represent the estimated fair value of derivatives scheduled to settle over the next twelve months based on market prices/rates as of the respective balance sheet dates. The derivative settlement amounts are not due until the month in which the related hedged transaction occurs. Cash settlements of our derivative instruments are generally classified as operating cash flows unless the derivative is deemed to contain, for accounting purposes, a significant financing element at contract inception, in which case these cash settlements are classified as financing cash flows in the accompanying condensed consolidated statements of cash flows.
The following table presents the fair value and location of each classification of derivative instrument disclosed in the condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012 on a gross basis without regard to same-counterparty netting:
				Fair Value
		Balance Sheet Location		September 30,				December 31,
				2013				2012
				($ in millions)
Asset Derivatives:
Not designated as hedging instruments:
Commodity contracts		Short-term derivative instruments		$	115			$	110
Commodity contracts		Long-term derivative instruments		11				5
Total				126				115
Liability Derivatives:
Designated as hedging instruments:
Foreign currency contracts		Long-term derivative instruments		(5		)		(20		)
Total				(5		)		(20		)
Not designated as hedging instruments:
Commodity contracts		Short-term derivative instruments		(265		)		(157		)
Commodity contracts		Long-term derivative instruments		(444		)		(882		)
Interest rate contracts		Short-term derivative instruments		(9		)		—
Interest rate contracts		Long-term derivative instruments		(79		)		(35		)
Total				(797		)		(1,074		)
Total derivative instruments				$	(676	)		$	(979	)
All of the Company’s derivative positions are subject to netting arrangements which provide for offsetting of asset and liability positions, as well as related cash collateral if applicable. Such netting arrangements generally do not have restrictions. Under such netting arrangements, the Company offsets the fair value of derivative instruments with cash collateral received or paid for those contracts executed with the same counterparty, which reduces the Company’s total assets and liabilities. As of September 30, 2013 and December 31, 2012, we did not have any cash collateral balances for these derivatives.
The following tables present the netting offsets of derivative assets and liabilities as of September 30, 2013 and December 31, 2012:
		30-Sep-13
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
Commodity Contracts:
Gross amounts of recognized assets (liabilities)		$	115			$	11			$	(265	)		$	(444	)
Gross amounts offset in the condensed consolidated		(104		)		(9		)		104				9
balance sheet
Net amounts of assets (liabilities) presented in the		11				2				(161		)		(435		)
condensed consolidated balance sheet
Interest Rate Contracts:
Gross amounts of recognized assets (liabilities)		—				—				(9		)		(79		)
Gross amounts offset in the condensed consolidated		—				—				—				—
balance sheet
Net amounts of assets (liabilities) presented in the		—				—				(9		)		(79		)
condensed consolidated balance sheet
Foreign Currency Contracts:
Gross amounts of recognized assets (liabilities)		—				—				—				(5		)
Gross amounts offset in the condensed consolidated		—				—				—				—
balance sheet
Net amounts of assets (liabilities) presented in the		—				—				—				(5		)
condensed consolidated balance sheet
Total derivatives as reported		$	11			$	2			$	(170	)		$	(519	)
		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		58				2				(105		)		(879		)
consolidated balance sheet
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		—				—				—				(35		)
consolidated balance sheet
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		—				—				—				(20		)
consolidated balance sheet
Total derivatives as reported		$	58			$	2			$	(105	)		$	(934	)
A consolidated summary of the effect of derivative instruments on the condensed consolidated statements of operations for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is provided below, separating fair value, cash flow and undesignated derivatives.
Fair Value Hedges
For interest rate derivative instruments designated as fair value hedges, the fair values of the hedges are recorded on the condensed consolidated balance sheets as assets or liabilities, with corresponding offsetting adjustments to the debt’s carrying value. We have elected not to designate any of our qualifying interest rate derivatives as fair value hedges. Therefore, changes in the fair value of all of our interest rate derivatives that occur prior to their maturity (i.e., temporary fluctuations in value) are reported in the condensed consolidated statements of operations within interest expense.
The following table presents the gain (loss) recognized in the condensed consolidated statements of operations for terminated instruments that were designated as fair value derivatives:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
Fair Value Derivatives		Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
Interest rate contracts		Interest expense		$	1			$	2			$	4			$	6
Cash Flow Hedges
A reconciliation of the changes of accumulated other comprehensive income (loss) in the condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Three Months Ended
		September 30,
		2013								2012
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
Balance, beginning of period		$	(286	)		$	(178	)		$	(306	)		$	(190	)
Net change in fair value		3				2				4				3
(Gains) losses reclassified to income		3				2				(9		)		(6		)
Balance, end of period		$	(280	)		$	(174	)		$	(311	)		$	(193	)
		Nine Months Ended
		September 30,
		2013								2012
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
Balance, beginning of period		$	(304	)		$	(189	)		$	(287	)		$	(178	)
Net change in fair value		3				2				4				3
(Gains) losses reclassified to income		21				13				(28		)		(18		)
Balance, end of period		$	(280	)		$	(174	)		$	(311	)		$	(193	)
Approximately $166 million of the $174 million of accumulated other comprehensive loss as of September 30, 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 September 30, 2013, we expect to transfer approximately $22 million of net loss included in accumulated other comprehensive income to net income (loss) during the next 12 months. The remaining amount will be transferred by December 31, 2022. As of September 30, 2013, none of our open commodity derivative instruments were designated as cash flow hedges.
The following table presents the pre-tax gain (loss) recognized in, and reclassified from, accumulated other comprehensive income (AOCI) related to instruments designated as cash flow derivatives:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
Cash Flow Derivatives		Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
Gain (Loss) Recognized in AOCI (Effective Portion):
Foreign currency		AOCI		$	3			$	4			$	3			$	4
contracts
				$	3			$	4			$	3			$	4
Gain (Loss) Reclassified from AOCI (Effective Portion):
Commodity		Natural gas, oil and		$	(3	)		$	9			$	(21	)		$	28
contracts		NGL sales
				$	(3	)		$	9			$	(21	)		$	28
Undesignated Derivatives
The following table presents the gain (loss) recognized in the condensed consolidated statements of operations for instruments not designated as either cash flow or fair value hedges:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
Derivative Contracts		Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
Commodity contracts		Natural gas, oil and		$	(250	)		$	(36	)		$	162			$	796
		NGL sales
Interest rate contracts		Interest expense		2				—				(55		)		(2		)
Total				$	(248	)		$	(36	)		$	107			$	794
Credit Risk
Derivative instruments that enable us to manage our exposure to natural gas, oil and NGL prices and interest rate volatility expose us to credit risk from our counterparties. To mitigate this risk, we enter into derivative contracts only with counterparties that are rated investment-grade and deemed by management to be competent and competitive market makers, and we attempt to limit our exposure to non-performance by any single counterparty. As of September 30, 2013, our natural gas, oil and interest rate derivative instruments were spread among 15 counterparties. Additionally, counterparties to our multi-counterparty secured hedging facility described previously are required to secure their obligations in excess of defined thresholds. We use this facility for substantially all of our natural gas, oil and NGL derivatives.

Divestitures_Note

Divestitures (Note)	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
Mergers, Acquisitions and Dispositions Disclosure [Text Block]	'
	Divestitures
	Natural Gas and Oil Properties
	Under full cost accounting rules, we account 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 typically do not involve a significant change in proved reserves or significantly alter the relationship between costs and proved reserves. In conjunction with certain sales, affiliates of our former Chief Executive Officer, Aubrey K. 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 net proceeds were paid to the sellers based on their respective ownership. These interests were acquired through the Founder Well Participation Program, which provides Mr. McClendon a contractual right to participate and invest as a working interest owner (with up to a 2.5% working interest) in new wells drilled on the Company’s leasehold through June 2014.
	In the Current Quarter, we sold assets in the Haynesville Shale to EXCO Operating Company, LP (EXCO) for net proceeds of approximately $257 million. We may receive up to an additional $32 million of net proceeds pursuant to customary 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 the Current Quarter, we sold assets in the northern Eagle Ford Shale to EXCO for net proceeds of approximately $617 million. In the Current Quarter, we received approximately $4 million of net proceeds for customary post-closing adjustments and may receive up to an additional $64 million of net proceeds pursuant to further customary post-closing adjustments. The assets sold included approximately 55,000 net acres in Zavala, Dimmit, La Salle and Frio counties, Texas.
	In the Prior Quarter, we sold producing assets in the Midland Basin portion of the Permian Basin to affiliates of Houston-based EnerVest, Ltd. for approximately $376 million in cash
	In the Prior Quarter, 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 the Prior Period, we sold approximately 60,000 net acres of leasehold in the Texoma Woodford play in Bryan, Carter, Johnston and Marshall counties, Oklahoma to XTO Energy Inc., a subsidiary of Exxon Mobil Corporation (NYSE:XOM), for net proceeds of approximately $572 million.
	During the Current Period and the Prior Period, we received proceeds of approximately $800 million and $180 million, respectively, from various other divestitures of natural gas and oil properties.
	Joint Ventures
	On June 28, 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 in the Mississippi Lime play in northern Oklahoma (425,000 acres net to Sinopec). The total consideration for the transaction was approximately $1.020 billion in cash, of which approximately $949 million of net proceeds, or 93%, 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 customary post-closing adjustments. All future exploration and development costs in the joint venture will be shared proportionately between the parties with no drilling carries involved.
	As of September 30, 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		Sinopec	Jun-13		50.00%		$	949		(d)	$	—		$	949		$	—
	Lime
	Utica		TOT	December 2011		25.00%		610				1,422		(e)	2,032			714
	Niobrara		CNOOC	Feb-11		33.30%		570				697		(f)	1,267			233
	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		$	947
	____________________________________________
	(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 September 30, 2013.
	(d)	Excludes $71 million of net proceeds (or 7% of the total transaction) expected to be received pursuant to certain customary 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 the Current Period and the Prior Period, our drilling and completion costs included the benefit of approximately $669 million and $655 million, respectively, in drilling and completion carries paid by our joint venture partners.
	During the Current Period and the Prior Period, we sold interests in additional leasehold we acquired in the Marcellus, Barnett and Utica Shale plays to our joint venture partners TOT and STO for approximately $48 million and $228 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 have the responsibility to bear the cost of producing the reserves attributable to such interests, which we include as a component of production expenses and production taxes in our condensed consolidated statements of operations in the periods such costs are incurred. As with all non-expense-bearing royalty interests, volumes conveyed in a VPP transaction are excluded from our estimated proved reserves; however, the estimated production expenses and taxes associated with VPP volumes expected to be delivered in future periods are included as a reduction of the future net cash flows attributable to our proved reserves for purposes of determining the cost center ceiling 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	Division		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 for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:
			Three Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
10		3.7		131			371.9			6.7
9		4.1		52.3			140.3			5.2
8		16.6		—			—			16.6
6		1.2		6			—			1.2
5		1.9		6.7			—			1.9
4		2.4		13.9			—			2.6
3		2		—			—			2
2		2.6		—			—			2.6
1		3.5		—			—			3.5
		38		209.9			512.2			42.3
		Three Months Ended September 30, 2012
VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		5.3		206			503.7			9.5
9		4.5		60.8			158			5.8
8		19.4		—			—			19.4
7		0.2		147.3			—			1
6		1.3		6			—			1.4
5		2.2		6.6			—			2.2
4		2.9		15.8			—			3
3		2.3		—			—			2.3
2		2.8		—			—			2.8
1		3.7		—			—			3.7
		44.6		442.5			661.7			51.1
		Nine Months Ended September 30, 2013
VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		11.4		426			1,158.60			20.9
9		12.5		162.5			433			16
8		51.6		—			—			51.6
6		3.6		18			—			3.7
5		5.7		19			—			5.8
4		7.8		42.7			—			8.1
3		6.2		—			—			6.2
2		7.9		—			—			7.9
1		10.9		—			—			10.9
		117.6		668.2			1,591.60			131.1
		Nine Months Ended September 30, 2012
VPP #		Natural Gas		Oil			NGL			Total
		(bcf)		(mbbl)			(mbbl)			(bcfe)
10		13.5		547			1,286.60			24.5
9		14		191			490.6			18.1
8		61.1		—			—			61.1
7		0.4		490.3			—			3.4
6		4.1		18			—			4.2
5		6.8		21.2			—			6.9
4		9		48.7			—			9.3
3		7.1		—			—			7.1
2		8.6		—			—			8.6
1		11.5		—			—			11.5
		136.1		1,316.20			1,777.20			154.7
The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2013 were as follows:
			Volume Remaining as of September 30, 2013
VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
		(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
10		101	57.1			1.8			6.3			106.1
9		89	89.5			1.1			3.1			114.4
8		23	112			—			—			112
6		76	22.6			0.2			—			23.6
5		40	18.7			0.1			—			19
4		39	27.2			0.1			—			28.1
3		70	33			—			—			33
2		67	23.1			—			—			23.1
1		111	109			—			—			109
			492.2			3.3			9.4			568.3
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)	9 Months Ended
	Sep. 30, 2013
Investments [Abstract]	'
Investments Disclosure [Text Block]	'
	Investments
	A summary of our investments, including our approximate ownership percentage as of September 30, 2013, is presented below.
				Carrying Value
		Approximate	Accounting	September 30,		December 31,
		Ownership %	Method	2013		2012
				($ in millions)
	FTS International, Inc.	30%	Equity	$	318	$	298
	Chaparral Energy, Inc.	20%	Equity	145		141
	Sundrop Fuels, Inc.	50%	Equity	97		111
	Twin Eagle Resource Management, LLC	30%	Equity	30		34
	Maalt Specialized Bulk, LLC	49%	Equity	13		13
	Clean Energy Fuels Corp.	—	Fair Value	—		12
	(common stock)
	Clean Energy Fuels Corp.	—	Cost	—		100
	(convertible notes)
	Gastar Exploration Ltd.	—	Fair Value	—		8
	Other	—	—	12		11
	Total investments			$	615	$	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.
	During the Current Period, we recorded negative equity method adjustments, prior to intercompany profit eliminations, of $17 million for our share of FTS’s net loss and recorded an accretion adjustment of $34 million related to the excess of our underlying equity in net assets of FTS over our carrying value. The carrying value of our investment in FTS was less than our underlying equity in net assets by approximately $333 million as of September 30, 2013, of which $31 million was attributed to goodwill. During the Current Period, the value attributed to goodwill decreased by $265 million, which represents our proportionate share, net of tax, of an impairment recorded by FTS related to its goodwill. The value not attributed to goodwill is being accreted over the nine-year weighted average estimated useful life of the underlying assets. Additionally, in the Current Period, we purchased FTS common stock offered to existing stockholders for $3 million.
	Chaparral Energy, Inc. Chaparral Energy, Inc. (Chaparral), based in Oklahoma City, Oklahoma, is a private independent oil and natural gas company engaged in the production, acquisition and exploitation of oil and natural gas properties.
	In the Current Period, we recorded positive equity method adjustments of $11 million related to our share of Chaparral’s net income, a $4 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 $49 million as of September 30, 2013. This excess is attributed to the natural gas and oil reserves held by Chaparral and is being amortized over the estimated life of these reserves based on a unit of production rate.
	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 the Current Period, we recorded a $14 million charge related to our share of Sundrop’s net loss. The carrying value of our investment in Sundrop was in excess of our underlying equity in net assets by approximately $53 million as of September 30, 2013. This excess will be amortized over the life of the plant, once it is placed into service.
	Twin Eagle Resource Management LLC. Twin Eagle Resource Management LLC (Twin Eagle) is a natural gas trading and management firm. During the Current Period, we recorded a $4 million charge related to our share of Twin Eagle’s net loss.
	Maalt Specialized Bulk, LLC. Maalt Specialized Bulk, LLC (Maalt) is engaged in bulk transportation services of sand. During the Current Period, we recorded a nominal positive equity method adjustment related to our share of Maalt's net income.
	Clean Energy Fuels Corp. Clean Energy Fuels Corp. (Nasdaq:CLNE) (Clean Energy), based in Seal Beach, California, builds and operates compressed natural gas (CNG) and liquefied natural gas (LNG) fueling stations; manufactures CNG and LNG equipment and technologies; converts vehicles to natural gas; and develops renewable natural gas production facilities.
	In the Current Quarter, we sold all of our shares of Clean Energy common stock for cash proceeds of approximately $13 million. We recorded a $3 million gain related to the sale.
	In the Current Period, 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. Gastar Exploration Ltd. (NYSE MKT:GST) (Gastar), based in Houston, Texas, is an independent energy company engaged in the exploration, development and production of natural gas and oil in the U.S. In the Current Period, we sold our investment in Gastar for cash proceeds of $10 million.
	Other. In the Current Period, we sold an equity investment for cash proceeds of $6 million and recorded a $5 million gain associated with the transaction.

Variable_Interest_Entities_Not

Variable Interest Entities (Note)	9 Months Ended
	Sep. 30, 2013
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]	'
Variable Interest Entities Disclosure [Text Block]	'
	Variable Interest Entities
	We consolidate the activities of VIEs of which we are the primary beneficiary. The primary beneficiary of a VIE is that variable interest holder possessing a controlling financial interest through (i) its power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) its obligation to absorb losses or its right to receive benefits from the VIE that could potentially be significant to the VIE. In order to determine whether we own a variable interest in a VIE, we perform qualitative analysis of the entity’s design, organizational structure, primary decision makers and relevant agreements.
	Consolidated VIE
	Chesapeake Granite Wash Trust. For a discussion of the formation, operations and presentation of the Trust, please see Noncontrolling Interests in Note 6. The Trust is considered a VIE due to the lack of voting or similar decision-making rights by its equity holders regarding activities that have a significant effect on the economic success of the Trust. Our ownership in the Trust and our obligations under the development agreement and related drilling support lien constitute variable interests. We have determined that we are the primary beneficiary of the Trust because (i) we have the power to direct the activities that most significantly impact the economic performance of the Trust via our obligations to perform under the development agreement, and (ii) as a result of the subordination and incentive thresholds applicable to the subordinated units we hold in the Trust, we have the obligation to absorb losses and the right to receive residual returns that could potentially be significant to the Trust. As a result, we consolidate the Trust in our financial statements, and the common units of the Trust owned by third parties are reflected as a noncontrolling interest.
	The Trust is a consolidated entity whose legal existence is separate from Chesapeake and our other consolidated subsidiaries, and the Trust is not a guarantor of any of Chesapeake’s debt. The creditors or beneficial holders of the Trust have no recourse to the general credit of Chesapeake; however, we have certain obligations to the Trust through the development agreement that are secured by a drilling support lien on our retained interest in the development wells up to a specified maximum amount recoverable by the Trust, which could result in the Trust acquiring all or a portion of our retained interest in the undeveloped portion of an area of mutual interest, if we do not meet our drilling commitment. In consolidation, as of September 30, 2013, approximately $337 million of net natural gas and oil properties, $24 million of current liabilities, $1 million of cash and cash equivalents, $7 million of short-term derivative liabilities and $1 million of long-term derivative liabilities were attributable to the Trust. We have presented parenthetically on the face of the condensed consolidated balance sheets the assets of the Trust that can be used only to settle obligations of the Trust and the liabilities of the Trust for which creditors do not have recourse to the general credit of Chesapeake.
	Unconsolidated VIE
	Mineral Acquisition Company I, L.P. In 2012, MAC-LP, L.L.C., a wholly owned non-guarantor unrestricted subsidiary of Chesapeake, entered into a partnership agreement with KKR Royalty Aggregator LLC (KKR) to form Mineral Acquisition Company I, L.P. The purpose of the partnership is to acquire mineral interests, or royalty interests carved out of mineral interests, in oil and natural gas basins in the continental United States. We are committed to acquire for our own account (outside the partnership) 10% of any acquisition agreed upon by the partnership up to a maximum of $25 million, and the partnership will acquire the remaining 90% up to a maximum of $225 million, funded entirely by KKR, making KKR the sole equity investor. We have significant influence over the decisions made by the partnership, as we hold two of five seats on the board of directors. We will receive proportionate distributions from the partnership of any cash received from royalties in excess of expenses paid, ranging from 7% to 22.5%. The partnership is considered a VIE because KKR’s control over the partnership is disproportionate to its economic interest. This VIE remains unconsolidated as the power to direct the activities of the partnership is shared between the Company and KKR. We are using the equity method to account for this investment.

Net_Gains_Losses_on_Sales_of_F

Net Gains (Losses) on Sales of Fixed Assets (Note)	9 Months Ended
	Sep. 30, 2013
Gain (Loss) on Disposition of Property Plant Equipment [Abstract]	'
Net Gains on Sales of Fixed Assets Disclosure [Text Block]	'
	Net (Gains) Losses on Sales of Fixed Assets
	For assets outside of our full cost pool, the cost of assets retired or otherwise disposed of and the applicable accumulated depreciation are removed from accounts, and the resulting gain or loss is reflected as a component of operating expenses. A summary of our gains or losses by asset class for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
		($ in millions)
	Gathering systems and treating plants	$	(132	)	$	(7	)	$	(311	)	$	(8	)
	Drilling rigs and equipment	—			10			1			12
	Buildings and land	1			—			24			—
	Other	(1		)	4			(4		)	1
	Total net (gains) losses on sales of fixed assets	$	(132	)	$	7		$	(290	)	$	5
	Gathering Systems and Treating Plants
	In the Current Quarter, our wholly owned midstream subsidiary, 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 pre-tax 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 the Current Period, 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 pre-tax 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 the Current Period, 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 pre-tax gain associated with this transaction.
	Buildings and Land
	In the Current Period, the net losses on sales of buildings and land were primarily from the sale of certain of our buildings and land in our Barnett Shale operating area.

Impairments_Note

Impairments (Note)	9 Months Ended
	Sep. 30, 2013
Asset Impairment Charges [Abstract]	'
Asset Impairment Charges [Text Block]	'
	Impairments
	Impairment of Natural Gas and Oil Properties
	On a quarterly basis, we analyze our unevaluated leasehold and transfer to evaluated 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. 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 from proved reserves (adjusted for cash flow hedges) less estimated future expenditures to be incurred in developing and producing the proved reserves, less any related income tax effects. In the Prior Quarter, 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. For the ceiling test calculation, costs used are those as of the end of the appropriate quarterly period, and estimated future net revenues are calculated using the unweighted arithmetic average of natural gas and oil 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. Cash flow hedges as of September 30, 2012, which related to future periods, increased the ceiling test impairment by $279 million.
	Impairments of Fixed Assets and Other
	We test our long-lived assets, other than natural gas and oil properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable and recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value. A summary of our impairments of fixed assets by asset class and other charges for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		($ in millions)
	Buildings and land	$	8	$	7	$	247	$	227
	Drilling rigs and equipment	24		31		27		54
	Gathering systems	21		—		22		—
	Other	32		—		47		—
	Total impairments of fixed assets and other	$	85	$	38	$	343	$	281
	Buildings and Land. In June 2013, we determined we would sell certain of our buildings and land (other than our core campus) in the Oklahoma City area. These assets are being actively marketed and we believe it is probable that these assets will be sold over the next 12 months. As a result, these assets qualified as held for sale as of September 30, 2013. We recognized an impairment loss of $138 million during the Current Period on these assets for the difference between the carrying amount and fair value of the assets, less the anticipated costs to sell.
	Given the impairment losses associated with these assets, we tested other noncore buildings and land that we own in the Oklahoma City area for recoverability in the Current Period. 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 $44 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. The buildings and land are included in our other segment. In addition, in the Current Period, we recognized an impairment loss of $28 million related to three office buildings in the Oklahoma City area. We received a purchase offer from a third party that we used to determine the fair value of the office buildings. As of September 30, 2013, the office buildings were classified as held for sale and included in our other segment. We anticipate selling the buildings in the 2013 fourth quarter.
	Due to a decrease in the estimated market prices of certain surface land classified as held for sale in the Fort Worth area, in the Current Period we recognized an additional impairment loss of $31 million. See below for discussion of the impairment of Barnett surface land in the Prior Period. We measured the fair value of these assets based on recent prices from orderly sales transactions for comparable properties between market participants. The surface land is included in our other segment.
	In the Prior Period, we recognized $227 million of impairment losses associated with an office building and surface land located in our Barnett Shale operating area. Due to depressed natural gas prices, we initiated a significant reduction in our Barnett Shale operations. The change in business climate in the Barnett Shale required us to test these long-lived assets for recoverability in the Prior Period. 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. The office building and surface land are included in our other segment.
	Drilling Rigs and Equipment. In the Current Quarter, we recognized $24 million of impairment losses on eight owned drilling rigs (seven of which are classified as held for sale assets as of September 30, 2013). In the Prior Quarter, we negotiated the purchase of 22 rigs previously sold in our sale leaseback transactions described in Note 4 from various lessors for an aggregate purchase price of $53 million, of which $25 million was deemed to be early lease termination costs and was recognized as impairments of fixed assets and other in the condensed consolidated statement of operations. In addition, in the Prior Quarter and the Prior Period, we recognized $6 million and $20 million, respectively, of impairment losses on certain of our owned drilling rigs due to the expectation that these drilling rigs 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 to sell each rig in an orderly transaction between market participants. Also in the Prior Period, 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 the Current Quarter, we recognized approximately $18 million of impairment losses on certain of our gathering systems classified as held for sale as of September 30, 2013 and December 31, 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 to sell 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 the Current Quarter, we terminated a gas gathering agreement and recorded a charge of $26 million within impairments of fixed assets and other in the condensed consolidated statement of operations.

Restructuring_and_Other_Termin

Restructuring and Other Termination Benefits (Note)	9 Months Ended
	Sep. 30, 2013
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Activities Disclosure [Text Block]	'
	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 expect to incur a total cost of $70 million, of which approximately $31 million was recorded in the Current Quarter for employees terminated in September, and we expect to recognize the remaining $39 million in the 2013 fourth quarter for employees terminated in October. Of the $31 million in charges incurred in the Current Quarter, approximately $1 million was paid in the Current Quarter.
	During the Current Quarter and the Current Period, we also incurred charges of approximately $28 million and $42 million, respectively, related to other workforce reductions, including executive officer separations.
	On April 1, 2013, Aubrey K. McClendon, the co-founder of the Company, ceased serving as President and Chief Executive Officer (CEO) and as a director of the Company pursuant to his agreement with the Board of Directors announced on January 29, 2013. Mr. McClendon’s departure from the Company was treated as a termination without cause under his employment agreement. On April 18, 2013, the Company and Mr. McClendon entered into a Founder Separation and Services Agreement, effective January 29, 2013, regarding his separation from employment and to facilitate the relationship between the Company and Mr. McClendon as joint working interest owners of oil and gas wells, leases and acreage. In the Current Quarter and Current Period, we incurred charges of approximately $3 million and $67 million, respectively, 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. Employees had until February 7, 2013 to respond, and 211 employees accepted the offer. Certain employees have a separation date in the 2013 fourth quarter. We are recognizing the expense related to their termination benefits over their remaining service period, including $1 million recognized in the Current Quarter.
	Substantially all of the restructuring and other termination benefits in the Current Period are in the exploration and production operating segment. A summary of our restructuring and other termination benefits for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		($ in millions)
	Restructuring charges under workforce reduction plan:
	Salary expense	$	5	$	—	$	5	$	—
	Acceleration of stock-based compensation	25		—		25		—
	Other termination benefits	1		—		1		—
	Total restructuring charges	31		—		31		—
	under workforce reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense	—		—		11		—
	Acceleration of 2008 performance bonus	—		—		11		—
	“claw-back” feature
	Acceleration of stock-based compensation	—		—		22		—
	Acceleration of performance share unit awards	3		—		16		—
	Estimated aircraft usage benefits	—		—		7		—
	Total termination benefits provided to	3		—		67		—
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense	—		—		33		—
	Acceleration of stock-based compensation	1		—		28		—
	Other termination benefits	—		—		2		—
	Total termination benefits provided to	1		—		63		—
	VSP participants
	Other termination benefits	28		3		42		4
	Total restructuring and other termination benefits	$	63	$	3	$	203	$	4

Fair_Value_Measurements_Note

Fair Value Measurements (Note)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value Measurements Disclosure [Text Block]	'
	Fair Value Measurements
	Certain financial instruments are reported at fair value on the condensed 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 financial asset or liability and have the lowest priority. Chesapeake uses a market valuation approach based on available inputs and the following methods and assumptions to measure the fair values of its assets and liabilities, which may or may not be observable in the market.
	Recurring Fair Value Measurement
	Other Current Assets. Assets related to forfeited Company matches of employee contributions to Chesapeake’s 401(k) plan and deferred compensation plan are included in other current assets. The fair value of these assets is determined using quoted market prices as they consist of exchange traded securities.
	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 then 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 September 30, 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		$	93		$	—		$	—		$	93
	Other current liabilities		(89		)	—			—			(89		)
	Derivatives:
	Commodity assets		—			105			21			126
	Commodity liabilities		—			(103		)	(606		)	(709		)
	Interest rate liabilities		—			(88		)	—			(88		)
	Foreign currency liabilities		—			(5		)	—			(5		)
	Total derivatives		—			(91		)	(585		)	(676		)
	Total		$	4		$	(91	)	$	(585	)	$	(672	)
	The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis 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 the Current Period and the Prior Period 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)		338			(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—			1
	Settlements		93			—
	Ending Balance as of September 30, 2013		$	(585	)	$	—
	Beginning Balance as of January 1, 2012		$	(1,654	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		525			4
	Total purchases, issuances, sales and settlements:
	Sales		—			(6		)
	Settlements		56			—
	Ending Balance as of September 30, 2012		$	(1,073	)	$	(2	)
	___________________________________________
	(a)		Natural Gas, Oil and						Interest Expense
	NGL Sales
		2013			2012			2013			2012
		($ in millions)
Total gains (losses) included in earnings for the period		$	338		$	525		$	(1	)	$	4
Change in unrealized gains (losses) relating to assets still held at reporting date		$	327		$	370		$	—		$	(2	)
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 will 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 will decrease (increase) the fair value of natural gas and oil derivatives and adverse changes to our counterparties’ creditworthiness will decrease 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			September 30,
								2013
								($ in millions)
Oil Trades(a)		Oil price volatility curves		9.94% - 25.79%	16.44		%	$	(369	)
Oil Basis Swaps(b)		Physical pricing point forward		$3.03 - $4.65	$	4.33		$	1
		curves
Natural Gas Trades(a)		Natural gas price volatility		20.08% - 34.86%	22.1		%	$	(215	)
		curves
Natural Gas Basis Swaps(b)		Physical pricing point forward		($1.64) - $0	$	(0.36	)	$	(2	)
		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 the Current Period, 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. See Note 12 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.
		30-Sep-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)		$	10,470		$	11,333		$	9,759		$	10,457
Long-term debt (Level 2)		$	2,252		$	2,241		$	2,378		$	2,284

Segment_Information_Note

Segment Information (Note)	9 Months Ended
	Sep. 30, 2013
Segment Reporting, Disclosure of Entity's Reportable Segments [Abstract]	'
Segment Information Disclosure [Text Block]	'
	Segment Information
	In accordance with accounting guidance for disclosures about segments of an enterprise and related information, we have three reportable operating segments. Our exploration and production operating segment, natural gas, oil and NGL marketing, gathering and compression operating segment and oilfield services operating segment are managed separately because of the nature of their 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 primarily from Chesapeake-operated wells. The oilfield services operating segment is responsible for contract drilling, oilfield trucking, oilfield rentals, hydraulic fracturing and other oilfield services operations for both Chesapeake-operated wells and wells operated by third parties.
	Management evaluates the performance of our segments based upon income (loss) before income taxes. Revenues from the sale of natural gas, oil and NGL related to Chesapeake’s ownership interests by the marketing, gathering and compression operating segment are reflected as revenues within our exploration and production operating segment. Such amounts totaled $2.002 billion, $1.541 billion, $5.682 billion and $3.877 billion for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, 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 $306 million, $330 million, $1.041 billion and $988 million for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, respectively. The following table presents selected financial information for Chesapeake’s operating segments:
		Exploration			Marketing,			Oilfield			Other			Intercompany			Consolidated
		and			Gathering			Services						Eliminations			Total
		Production			and
					Compression
		($ in millions)
	Three Months Ended
	September 30, 2013:
	Revenues	$	1,586		$	5,034		$	551		$	4		$	(2,308	)	$	4,867
	Intersegment revenues	—			(2,002		)	(306		)	—			2,308			—
	Total revenues	$	1,586		$	3,032		$	245		$	4		$	—		$	4,867
	Income (Loss) Before	$	430		$	128		$	(37	)	$	(48	)	$	(86	)	$	387
	Income Taxes
	Three Months Ended
	September 30, 2012:
	Revenues	$	1,437		$	2,922		$	482		$	—		$	(1,871	)	$	2,970
	Intersegment revenues	—			(1,541		)	(330		)	—			1,871			—
	Total revenues	$	1,437		$	1,381		$	152		$	—		$	—		$	2,970
	Income (Loss) Before	$	(3,073	)	$	120		$	(2	)	$	(152	)	$	(124	)	$	(3,231	)
	Income Taxes
	Nine Months Ended
	September 30, 2013:
	Revenues	$	5,444		$	12,553		$	1,677		$	27		$	(6,736	)	$	12,965
	Intersegment revenues	—			(5,682		)	(1,041		)	(13		)	6,736			—
	Total revenues	$	5,444		$	6,871		$	636		$	14		$	—		$	12,965
	Income (Loss) Before	$	654		$	395		$	(12	)	$	808		$	(284	)	$	1,561
	Income Taxes
	Nine Months Ended
	September 30, 2012:
	Revenues	$	4,622		$	7,587		$	1,434		$	—		$	(4,865	)	$	8,778
	Intersegment revenues	—			(3,877		)	(988		)	—			4,865			—
	Total revenues	$	4,622		$	3,710		$	446		$	—		$	—		$	8,778
	Income (Loss) Before	$	(1,896	)	$	1,279		$	96		$	(654	)	$	(362	)	$	(1,537	)
	Income Taxes
	As of
	September 30, 2013:
	Total Assets	$	35,919		$	2,323		$	1,981		$	5,014		$	(2,949	)	$	42,288
	As of
	December 31, 2012:
	Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information (Note)	9 Months Ended
	Sep. 30, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Condensed Financial Information of Parent Company Only Disclosure [Text Block]	'
	Condensed Consolidating Financial Information
	Chesapeake Energy Corporation is a holding company, owns no operating assets, and has no significant operations independent of its subsidiaries. Our obligations under our outstanding senior notes and contingent convertible senior notes listed in Note 3 are fully and unconditionally guaranteed, jointly and severally, by certain of our wholly 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. Our midstream subsidiary, CMD, and certain of its subsidiaries, including Chesapeake Midstream Operating, L.L.C. (CMO), were added as guarantors of our senior notes and certain other obligations in June 2012 upon the termination of the midstream credit facility. In December 2012 upon the sale of CMO to ACMP, CMO and its subsidiaries were then released as guarantors of our senior notes and of our other debt obligations, and all prior year information was restated at that time to reflect CMO and its subsidiaries as non-guarantor subsidiaries and CMD and certain of its remaining subsidiaries as guarantor subsidiaries. Certain of our oilfield services subsidiaries, 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 September 30, 2013 and December 31, 2012 and for the three and nine months ended September 30, 2013 and 2012. Such financial information may not necessarily be indicative of our results of operations, cash flows or financial position had these subsidiaries operated as independent entities.
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF SEPTEMBER 30, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	966		$	—		$	14		$	7		$	987
	Restricted cash		—			—			82			(7		)	75
	Other		104			2,606			645			(423		)	2,932
	Current assets held for sale		—			—			—			—			—
	Intercompany receivable, net		25,863			—			—			(25,863		)	—
	Total Current Assets		26,933			2,606			741			(26,286		)	3,994
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,245			3,123			151			32,519
	Other property and equipment, net		—			2,561			1,445			(1		)	4,005
	Property and equipment held for sale, net		—			571			26			—			597
	Total Property and Equipment,		—			32,377			4,594			150			37,121
	Net
	LONG-TERM ASSETS:
	Other assets		114			1,316			115			(372		)	1,173
	Investments in subsidiaries and		2,211			(238		)	—			(1,973		)	—
	intercompany advances
	TOTAL ASSETS		$	29,258		$	36,061		$	5,450		$	(28,481	)	$	42,288
	CURRENT LIABILITIES:
	Current liabilities		$	242		$	5,427		$	431		$	(422	)	$	5,678
	Intercompany payable, net		—			24,740			1,279			(26,019		)	—
	Total Current Liabilities		242			30,167			1,710			(26,441		)	5,678
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,801			—			935			—			12,736
	Deferred income tax liabilities		638			2,397			60			328			3,423
	Other long-term liabilities		381			1,286			900			(464		)	2,103
	Total Long-Term Liabilities		12,820			3,683			1,895			(136		)	18,262
	EQUITY:
	Chesapeake stockholders’ equity		16,196			2,211			1,845			(4,056		)	16,196
	Noncontrolling interests		—			—			—			2,152			2,152
	Total Equity		16,196			2,211			1,845			(1,904		)	18,348
	TOTAL LIABILITIES AND EQUITY		$	29,258		$	36,061		$	5,450		$	(28,481	)	$	42,288
	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			2,378			512			(345		)	2,546
	Current assets held for sale		—			—			4			—			4
	Intercompany receivable, net		25,356			—			—			(25,356		)	—
	Total Current Assets		25,585			2,378			686			(25,701		)	2,948
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,083			3,057			(222		)	31,918
	Other property and equipment, net		—			3,066			1,549			—			4,615
	Property and equipment held for sale, net		—			255			379			—			634
	Total Property and Equipment,		—			32,404			4,985			(222		)	37,167
	Net
	LONG-TERM ASSETS:
	Other assets		217			1,396			261			(378		)	1,496
	Investments in subsidiaries and		2,241			(186		)	—			(2,055		)	—
	intercompany advances
	TOTAL ASSETS		$	28,043		$	35,992		$	5,932		$	(28,356	)	$	41,611
CURRENT LIABILITIES:
Current liabilities		$	789		$	5,377		$	424		$	(345	)	$	6,245
Current liabilities held for sale		—			—			21			—			21
Intercompany payable, net		—			24,166			1,312			(25,478		)	—
Total Current Liabilities		789			29,543			1,757			(25,823		)	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			2,241			2,141			(4,382		)	15,569
Noncontrolling interests		—			—			—			2,327			2,327
Total Equity		15,569			2,241			2,141			(2,055		)	17,896
TOTAL LIABILITIES AND EQUITY		$	28,043		$	35,992		$	5,932		$	(28,356	)	$	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 $228 million, which was incorrectly presented in the Guarantor subsidiaries as of December 31, 2012. The impact of this error was not material to any previously issued financial statements.
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	1,400		$	185		$	1		$	1,586
Marketing, gathering and compression		—			3,031			1			—			3,032
Oilfield services		—			—			552			(303		)	249
Total Revenues		—			4,431			738			(302		)	4,867
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			268			14			—			282
Production taxes		—			60			2			—			62
Marketing, gathering and compression		—			3,009			—			—			3,009
Oilfield services		—			23			460			(272		)	211
General and administrative		—			97			24			(1		)	120
Restructuring and other termination benefits		—			63			—			—			63
Natural gas, oil and NGL depreciation,		—			591			61			—			652
depletion and amortization
Depreciation and amortization of other		—			43			74			(38		)	79
assets
Impairment of natural gas and oil		—			—			99			(99		)	—
properties
Impairments of fixed assets and other		—			56			29			—			85
Net (gains) losses on sales of		—			(133		)	—			1			(132		)
fixed assets
Total Operating Expenses		—			4,077			763			(409		)	4,431
INCOME (LOSS) FROM OPERATIONS		—			354			(25		)	107			436
OTHER INCOME (EXPENSE):
Interest expense		(207		)	(27		)	(21		)	215			(40		)
Losses on investments		—			(22		)	—			—			(22		)
Impairment of investment		—			—			(1		)	1			—
Gains (losses) on sales of investments		—			3			—			—			3
Other income (expense)		208			44			2			(244		)	10
Equity in net earnings of subsidiary		201			(75		)	—			(126		)	—
Total Other Income (Expense)		202			(77		)	(20		)	(154		)	(49		)
INCOME (LOSS) BEFORE INCOME		202			277			(45		)	(47		)	387
TAXES
INCOME TAX EXPENSE (BENEFIT)		—			134			(17		)	30			147
NET INCOME (LOSS)		202			143			(28		)	(77		)	240
Net income attributable to		—			—			—			(38		)	(38		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		202			143			(28		)	(115		)	202
TO CHESAPEAKE
Other comprehensive income (loss)		2			1			(2		)	—			1
COMPREHENSIVE INCOME (LOSS)		$	204		$	144		$	(30	)	$	(115	)	$	203
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	1,357		$	79		$	1		$	1,437
Marketing, gathering and compression		—			1,319			62			—			1,381
Oilfield services		—			—			485			(333		)	152
Total Revenues		—			2,676			626			(332		)	2,970
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			311			9			—			320
Production taxes		—			51			2			—			53
Marketing, gathering and compression		—			1,310			29			—			1,339
Oilfield services		—			80			361			(325		)	116
General and administrative		—			108			37			—			145
Restructuring and other termination benefits		—			2			1			—			3
Natural gas, oil and NGL depreciation,		—			716			46			—			762
depletion and amortization
Depreciation and amortization of other		—			43			58			(35		)	66
assets
Impairment of natural gas and oil properties		—			3,167			148			—			3,315
Impairments of fixed assets and other		—			8			30			—			38
Net (gains) losses on sales of		—			4			3			—			7
fixed assets
Total Operating Expenses		—			5,800			724			(360		)	6,164
INCOME (LOSS) FROM OPERATIONS		—			(3,124		)	(98		)	28			(3,194		)
OTHER INCOME (EXPENSE):
Interest expense		(289		)	(18		)	(21		)	292			(36		)
Losses on investments		—			(23		)	—			—			(23		)
Gains (losses) on sales of investments		—			—			31			—			31
Other income (expense)		286			79			3			(377		)	(9		)
Equity in net earnings (losses) of subsidiary		(2,010		)	(127		)	—			2,137			—
Total Other Income (Expense)		(2,013		)	(89		)	13			2,052			(37		)
INCOME (LOSS) BEFORE INCOME		(2,013		)	(3,213		)	(85		)	2,080			(3,231		)
TAXES
INCOME TAX EXPENSE (BENEFIT)		(1		)	(1,204		)	(33		)	(22		)	(1,260		)
NET INCOME (LOSS)		(2,012		)	(2,009		)	(52		)	2,102			(1,971		)
Net income attributable to		—			—			—			(41		)	(41		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(2,012		)	(2,009		)	(52		)	2,061			(2,012		)
TO CHESAPEAKE
Other comprehensive income (loss)		3			(7		)	(2		)	—			(6		)
COMPREHENSIVE INCOME (LOSS)		$	(2,009	)	$	(2,016	)	$	(54	)	$	2,061		$	(2,018	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,962		$	473		$	9		$	5,444
Marketing, gathering and compression		—			6,861			10			—			6,871
Oilfield services		—			—			1,703			(1,053		)	650
Total Revenues		—			11,823			2,186			(1,044		)	12,965
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			838			39			—			877
Production taxes		—			167			6			—			173
Marketing, gathering and compression		—			6,776			5			—			6,781
Oilfield services		—			70			1,362			(889		)	543
General and administrative		—			264			73			(1		)	336
Restructuring and other termination benefits		—			200			3			—			203
Natural gas, oil and NGL depreciation,		—			1,771			174			—			1,945
depletion and amortization
Depreciation and amortization of other		—			137			218			(121		)	234
assets
Impairment of natural gas and oil		—			—			260			(260		)	—
properties
Impairments of fixed assets and other		—			307			36			—			343
Net gains (losses) on sales of		—			(291		)	—			1			(290		)
fixed assets
Total Operating Expenses		—			10,239			2,176			(1,270		)	11,145
INCOME (LOSS) FROM OPERATIONS		—			1,584			10			226			1,820
OTHER INCOME (EXPENSE):
Interest expense		(703		)	(70		)	(63		)	672			(164		)
Losses on investments		—			(26		)	—			—			(26		)
Impairment of investment		—			(10		)	(1		)	1			(10		)
Gains (losses) on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	—			—			—			(70		)
Other income (expense)		651			120			7			(760		)	18
Equity in net earnings of subsidiary		916			(221		)	—			(695		)	—
Total Other Income (Expense)		794			(214		)	(57		)	(782		)	(259		)
INCOME (LOSS) BEFORE INCOME TAXES		794			1,370			(47		)	(556		)	1,561
INCOME TAX EXPENSE (BENEFIT)		(46		)	605			(18		)	53			594
NET INCOME (LOSS)		840			765			(29		)	(609		)	967
Net income attributable to		—			—			—			(127		)	(127		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		840			765			(29		)	(736		)	840
TO CHESAPEAKE
Other comprehensive income		2			12			(1		)	—			13
COMPREHENSIVE INCOME (LOSS)		$	842		$	777		$	(30	)	$	(736	)	$	853
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,410		$	209		$	3		$	4,622
Marketing, gathering and compression		—			3,555			155			—			3,710
Oilfield services		—			—			1,440			(994		)	446
Total Revenues		—			7,965			1,804			(991		)	8,778
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			989			16			—			1,005
Production taxes		—			137			4			—			141
Marketing, gathering and compression		—			3,549			82			—			3,631
Oilfield services		—			141			1,029			(849		)	321
General and administrative		—			343			93			—			436
Restructuring and other termination benefits		—			3			1			—			4
Natural gas, oil and NGL depreciation,		—			1,761			95			—			1,856
depletion and amortization
Depreciation and amortization of other		—			132			205			(104		)	233
assets
Impairment of natural gas and oil		—			3,167			148			—			3,315
properties
Impairment of fixed assets and other		—			227			54			—			281
Net (gains) losses on sales of		—			2			3			—			5
fixed assets
Total Operating Expenses		—			10,451			1,730			(953		)	11,228
INCOME (LOSS) FROM OPERATIONS		—			(2,486		)	74			(38		)	(2,450		)
OTHER INCOME (EXPENSE):
Interest expense		(682		)	(3		)	(64		)	686			(63		)
Earnings (losses) on investments		—			(142		)	55			—			(87		)
Gains on sales of investments		—			1,030			31			—			1,061
Other income (expense)		667			166			10			(841		)	2
Equity in net earnings (losses) of subsidiary		(1,060		)	(179		)	—			1,239			—
Total Other Income (Expense)		(1,075		)	872			32			1,084			913
INCOME (LOSS) BEFORE INCOME TAXES		(1,075		)	(1,614		)	106			1,046			(1,537		)
INCOME TAX EXPENSE (BENEFIT)		(6		)	(559		)	41			(75		)	(599		)
NET INCOME (LOSS)		(1,069		)	(1,055		)	65			1,121			(938		)
Net income attributable to		—			—			—			(131		)	(131		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(1,069		)	(1,055		)	65			990			(1,069		)
TO CHESAPEAKE
Other comprehensive income (loss)		3			(25		)	—			—			(22		)
COMPREHENSIVE INCOME (LOSS)		$	(1,066	)	$	(1,080	)	$	65		$	990		$	(1,091	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING		$	—		$	3,232		$	362		$	(33	)	$	3,561
ACTIVITIES
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to proved and unproved		—			(4,642		)	(639		)	—			(5,281		)
properties
Proceeds from divestitures of proved		—			2,736			53			—			2,789
and unproved properties
Additions to other property and		—			(415		)	(224		)	—			(639		)
equipment
Other investing activities		—			67			757			260			1,084
Net Cash Used In Investing Activities		—			(2,254		)	(53		)	260			(2,047		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities		—			6,311			825			—			7,136
borrowings
Payments on credit facilities borrowings		—			(6,310		)	(958		)	—			(7,268		)
Proceeds from issuance of senior notes,		2,274			—			—			—			2,274
net of discount and offering costs
Cash paid to purchase debt		(2,116		)	—			—			—			(2,116		)
Proceeds from sales of noncontrolling		—			5			—			—			5
interests
Other financing activities		(374		)	(297		)	46			(220		)	(845		)
Intercompany advances, net		954			(687		)	(267		)	—			—
Net Cash Provided By (Used In) Financing Activities		738			(978		)	(354		)	(220		)	(814		)
Net increase (decrease) in cash and cash		738			—			(45		)	7			700
equivalents
Cash and cash equivalents, beginning of		228			—			59			—			287
period
Cash and cash equivalents, end of period		$	966		$	—		$	14		$	7		$	987
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
NINE MONTHS ENDED SEPTEMBER 30, 2012
($ in millions)
		Parent(a)			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries(a)			Guarantor
								Subsidiaries
CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	2,779		$	200		$	(1,001	)	$	1,978
CASH FLOWS FROM INVESTING
ACTIVITIES:
Additions to proved and unproved		—			(10,208		)	(130		)	—			(10,338		)
properties
Proceeds from divestitures of proved		—			2,445			—			—			2,445
and unproved properties
Additions to other property and		—			(577		)	(1,339		)	—			(1,916		)
equipment
Other investing activities		—			3,051			(158		)	(1,238		)	1,655
Net Cash Used In Investing Activities		—			(5,289		)	(1,627		)	(1,238		)	(8,154		)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from credit facilities borrowings		—			12,116			1,870			—			13,986
Payments on credit facilities borrowings		—			(12,051		)	(1,563		)	—			(13,614		)
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		3,789			—			—			—			3,789
Proceeds from sales of noncontrolling interests		—			—			1,056			—			1,056
Other financing activities		(367		)	(154		)	(2,217		)	2,239			(499		)
Intercompany advances, net		(4,618		)	2,599			2,019			—			—
Net Cash Provided By Financing Activities		67			2,510			1,165			2,239			5,981
Change in cash and cash equivalents		(7		)	—			(7		)	—			(14		)
classified as current assets held for sale
Net increase in cash and cash equivalents		60			—			(269		)	—			(209		)
Cash and cash equivalents, beginning of		1			—			350			—			351
period
Cash and cash equivalents, end of period		$	61		$	—		$	81		$	—		$	142
___________________________________________
(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 $61 million, which was incorrectly presented as the Guarantor subsidiaries as of September 30, 2012. The impact of this error was not material to any previously issued financial statements.

Recently_Issued_Accounting_Sta

Recently Issued Accounting Standards (Note)	9 Months Ended
	Sep. 30, 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)	9 Months Ended
	Sep. 30, 2013
Subsequent Events [Abstract]	'
Subsequent Events Disclosure [Text Block]	'
	Subsequent Events
	On November 1, 2013, we terminated a financing master lease agreement on 106 surface properties in the Fort Worth area for $257 million. We anticipate recording a loss of approximately $120 million in the 2013 fourth quarter associated with this extinguishment. See Note 5 for additional information on this financing obligation.
	Subsequent to September 30, 2013, we acquired nine rigs subject to the master lease agreements described in Note 4. In conjunction with the purchases, we also terminated approximately $58 million of remaining lease commitments associated with these rigs. Total consideration paid was approximately $70 million and we anticipate recording a charge in the 2013 fourth quarter for the lease termination cost.

Basis_of_Presentation_and_Summ1

Basis of Presentation and Summary of Significant Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Consolidation, Policy [Policy Text Block]	'
	Principles of Consolidation
	The accompanying unaudited condensed consolidated financial statements of Chesapeake Energy Corporation (“Chesapeake” or the “Company”) and its subsidiaries have been prepared in accordance with the instructions to Form 10-Q as prescribed by the Securities and Exchange Commission (SEC). This Form 10-Q relates to the three and nine months ended September 30, 2013 (the “Current Quarter” and the “Current Period”, respectively) and the three and nine months ended September 30, 2012 (the “Prior Quarter” and the “Prior Period”, respectively). Chesapeake’s annual report on Form 10-K for the year ended December 31, 2012 (“2012 Form 10-K”) includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Form 10-Q. All material adjustments (consisting solely of normal recurring adjustments) which, in the opinion of management, are necessary for a fair presentation of the results for the interim periods have been reflected. The accompanying condensed consolidated financial statements of Chesapeake include the accounts of our direct and indirect wholly owned subsidiaries and entities in which Chesapeake holds a controlling interest. All significant intercompany accounts and transactions have been eliminated. The results for the Current Quarter and Current Period are not necessarily indicative of the results to be expected for the full year.
	Critical Accounting Policies
	We consider accounting policies related to variable interest entities, natural gas and oil properties, derivatives and income taxes to be critical policies. These policies are summarized in Item 7 of our 2012 Form 10-K.
Risks and Uncertainties, Policy [Policy Text Block]	'
	Risks and Uncertainties
	Our primary business strategy over the last few years was to continue growing our reserves and production while transitioning from an asset base primarily focused on natural gas to an asset base more balanced between natural gas and liquids production. This was a capital-intensive strategy, and we made capital expenditures historically and in the Current Period that exceeded our cash flow from operations, supplementing such cash flows with borrowings, proceeds from strategic joint ventures and sales of assets that we determined were noncore or did not fit our long-term plans. The full year 2013 gap between forecasted capital expenditures and expected cash flow from operations is approximately $3.5 billion; however, this expected spending gap has been fully covered by joint venture and asset sales proceeds received year to date. We are working to execute our business with greater financial discipline and are targeting to balance capital expenditures with cash flow from operations over time. We expect to have the flexibility to fund any short-term disparities using our $4.0 billion corporate revolving credit facility, which was undrawn at September 30, 2013. As we apply available cash from future asset sales and operations towards reducing our financial leverage and complexity, we may incur various cash and noncash charges including but not limited to impairments of fixed assets, lease termination charges or financing extinguishment costs.
	We continue to have significant exposure to natural gas prices. Approximately 70% of our estimated proved reserve volumes as of December 31, 2012 were natural gas, and natural gas represented approximately 73% and 80% of our natural gas, oil and NGL sales volumes for the Current Quarter and the year ended December 31, 2012, respectively. To add more certainty to our future estimated cash flows, we currently have downside price protection, in the form of over-the-counter derivative contracts, on approximately 80% of our remaining 2013 estimated natural gas production at an average price of $3.69 per mcf and 91% of our remaining 2013 estimated oil production at an average price of $95.59 per bbl. We also have derivative contracts providing downside price protection in 2014 on 251 bcf of natural gas at an average price of $4.22 per mcf and 22 mmbbls of oil at an average price of $93.79 per bbl. While our use of derivative contracts allows us to reduce our exposure to price volatility on our cash flows and EBITDA (defined as earnings before interest, taxes, depreciation, depletion and amortization), the derivative contracts we elect to enter into for any period depend on our outlook on future prices and our risk assessment. Low natural gas, oil and NGL prices can reduce our estimate of proved reserves, potentially resulting in a future write-down of the carrying value of our natural gas and oil properties. In 2012, when natural gas prices reached 10-year lows, we reduced our estimate of proved reserves by 3.1 tcfe, or 17%, primarily due to the impact of downward natural gas price revisions, and we incurred a $3.3 billion write-down of the carrying value of our natural gas and oil properties. Future impairments of the carrying value of our natural gas and oil properties, if any, will be dependent on many factors, including natural gas, oil and NGL prices, production rates, levels of reserves, the evaluation of costs excluded from amortization, the timing and impact of asset sales, future development costs and service costs.

Variable_Interest_Entities_Var

Variable Interest Entities Variable Interest Entity (Policies)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Consolidation, Variable Interest Entity, Policy [Policy Text Block]	'
	We consolidate the activities of VIEs of which we are the primary beneficiary.

Impairment_Policies

Impairment (Policies)	9 Months Ended
	Sep. 30, 2013
Property, Plant and Equipment [Abstract]	'
Impairment or Disposal of Long-Lived Assets, Policy [Policy Text Block]	'
	We test our long-lived assets, other than natural gas and oil properties, for recoverability whenever events or changes in circumstances indicate that carrying amounts may not be recoverable and recognize an impairment loss if the carrying amount of a long-lived asset is not recoverable and exceeds its fair value.

Recently_Issued_Accounting_Sta1

Recently Issued Accounting Standards Recently Issued Accounting Standards (Policies)	9 Months Ended
	Sep. 30, 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)	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Schedule Of Assets-held-for Sale [Table Text Block]	'
	A summary of the assets and liabilities held for sale on our condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012 is detailed below.
		September 30,				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	$	10			$	352
	Oilfield services equipment, net of accumulated depreciation	26				27
	Compressors, net of accumulated depreciation	242				—
	Buildings and land, net of accumulated depreciation	319				255
	Property and equipment held for sale, net	$	597			$	634
	Accounts payable	$	—			$	4
	Accrued liabilities	—				17
	Current liabilities held for sale	$	—			$	21
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	Accumulated Other Comprehensive Income (Loss)
	For the Current Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
		Net Gains				Net Gains				Total
		(Losses) on				(Losses)
		Cash Flow				on
		Hedges				Investments
		($ in millions)
	Balance, December 31, 2012	$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications	2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income	13				4				17
	Net current period other comprehensive income	15				(2		)		13
	Balance, September 30, 2013	$	(174	)		$	5			$	(169	)
	A reconciliation of the changes of accumulated other comprehensive income (loss) in the condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Three Months Ended
		September 30,
		2013								2012
		Before				After				Before			After
		Tax				Tax				Tax			Tax
		($ in millions)
	Balance, beginning of period	$	(286	)		$	(178	)		$	(306	)	$	(190	)
	Net change in fair value	3				2				4			3
	(Gains) losses reclassified to income	3				2				(9		)	(6		)
	Balance, end of period	$	(280	)		$	(174	)		$	(311	)	$	(193	)
		Nine Months Ended
		September 30,
		2013								2012
		Before				After				Before			After
		Tax				Tax				Tax			Tax
		($ in millions)
	Balance, beginning of period	$	(304	)		$	(189	)		$	(287	)	$	(178	)
	Net change in fair value	3				2				4			3
	(Gains) losses reclassified to income	21				13				(28		)	(18		)
	Balance, end of period	$	(280	)		$	(174	)		$	(311	)	$	(193	)
Reclassification out of Accumulated Other Comprehensive Income [Table Text Block]	'
	For the Current Quarter and the Current Period, amounts reclassified from accumulated other comprehensive income (loss), net of tax, into the condensed consolidated statement of operations are detailed below.
	Details About Accumulated	Affected Line Item		Three Months Ended				Nine Months Ended
	Other Comprehensive	in the Statement		30-Sep-13				30-Sep-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		$	2			$	13
	Investments:
	Impairment of investment	Impairment of investment		—				6
	Sale of investment	Gain on sale of investment		(2		)		(2		)
	Total reclassifications			$	—			$	17
	for the period, net of tax

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Antidilutive Securities Excluded From Computation Of Earnings Per Share [Table Text Block]	'
	For the Current Quarter, the Prior Quarter, the Current Period and the Prior Period, the following shares of cumulative convertible preferred stock and unvested restricted stock 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:
		Net Income		Shares
		Adjustments
		($ in millions)		(in millions)
	Three Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	3	2
	Three Months Ended September 30, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	21	56
	5.75% cumulative convertible preferred stock (series A)	$	16	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	3	5
	4.50% cumulative convertible preferred stock	$	3	6
	Unvested restricted stock	$	—	3
	Nine Months Ended September 30, 2013:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	40
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	14	3
	Nine Months Ended September 30, 2012:
	Common stock equivalent of our preferred stock outstanding:
	5.75% cumulative convertible preferred stock	$	64	56
	5.75% cumulative convertible preferred stock (series A)	$	47	39
	5.00% cumulative convertible preferred stock (series 2005B)	$	8	5
	4.50% cumulative convertible preferred stock	$	9	6
	Unvested restricted stock	$	—	4

Debt_Tables

Debt (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Schedule of Long-term Debt Instruments [Table Text Block]	'
	Our long-term debt consisted of the following as of September 30, 2013 and December 31, 2012:
			September 30, 2013				December 31, 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)		465				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		285				418
	Discount on senior notes and term loan(d)		(380		)		(465		)
	Interest rate derivatives(e)		14				20
	Total debt, net		12,736				12,620
	Less current maturities of long-term debt, net(f)		—				(463		)
	Total long-term debt, net		$	12,736			$	12,157
	___________________________________________
	(a)	The principal amount shown is based on the exchange rate of $1.3527 to €1.00 and $1.3193 to €1.00 as of September 30, 2013 and December 31, 2012, respectively. See Note 7 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 Current Quarter, 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 fourth quarter of 2013 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. During the Current Quarter, the notes were not convertible under this provision. 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		$	48.31			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		$	107.01			June 14, 2019
	(d)	Discount as of September 30, 2013 and December 31, 2012 included $322 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. The discount also included $34 million and $40 million as of September 30, 2013 and December 31, 2012, respectively, associated with our term loan discussed further below.
	(e)	See Note 7 for further discussion related to these instruments.
Schedule of Line of Credit Facilities [Table Text Block]	'
	In June 2012, we paid off and terminated our midstream credit facility. Our remaining revolving bank credit facilities are described below.
			Corporate				Oilfield Services
			Credit Facility(a)				Credit Facility(b)
			($ 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 September 30, 2013		$	—			$	285
	Letters of credit outstanding as of September 30, 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)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Contractual Obligation, Fiscal Year Maturity Schedule [Table Text Block]	'
	The aggregate undiscounted commitments under our gathering, processing and transportation agreements, excluding any reimbursement from working interest and royalty interest owners, are presented below.
		September 30, 2013
		($ in millions)
	2013	$	510
	2014	2,010
	2015	1,821
	2016	1,910
	2017	1,942
	2018 - 2099	9,546
	Total	$	17,739

Other_Liabilities_Other_Liabil

Other Liabilities Other Liabilities (Tables)	9 Months Ended
	Sep. 30, 2013
Other Liabilities [Abstract]	'
Other Current Liabilities [Table Text Block]	'
	Other current liabilities as of September 30, 2013 and December 31, 2012 are detailed below.
			September 30, 2013		December 31, 2012
			($ in millions)
	Revenues and royalties due others		$	1,621	$	1,337
	Accrued natural gas, oil and NGL drilling and production costs		417		525
	Joint interest prepayments received		472		749
	Accrued compensation and benefits		276		225
	Other accrued taxes		178		130
	Accrued dividends		102		101
	Other		559		674
	Total other current liabilities		$	3,625	$	3,741
Other Long-Term Liabilities [Table Text Block]	'
	Other long-term liabilities as of September 30, 2013 and December 31, 2012 are detailed below.
			September 30, 2013		December 31, 2012
			($ in millions)
	CHK Utica ORRI conveyance obligation(a)		$	256	$	275
	CHK C-T ORRI conveyance obligation(b)		153		164
	Financing obligations(c)		191		175
	Mortgages payable(d)		—		56
	Other		580		506
	Total other long-term liabilities		$	1,180	$	1,176
	____________________________________________
	(a)	$23 million and $18 million of the total $279 million and $293 million obligations are recorded in other current liabilities as of September 30, 2013 and December 31, 2012, respectively. See Note 6 for further discussion of the transaction.
	(b)	$10 million and $14 million of the total $163 million and $178 million obligations are recorded in other current liabilities as of September 30, 2013 and December 31, 2012, respectively. See Note 6 for further discussion of the transaction.
	(c)	Consists primarily of an obligation related to 111 real estate surface properties in the Fort Worth area that we financed in 2009 for approximately $145 million and we entered into a 40-year master lease agreement under which 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 condensed consolidated balance sheet. Chesapeake exercised its option to repurchase one of the properties in 2011 and four of the properties in the Current Period. See Note 18 for a discussion of the termination of this lease agreement on November 1, 2013.
	(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 the Current Period, we prepaid the term loan in full without penalty. As of September 30, 2013, the building was classified as property and equipment held for sale on our condensed consolidated balance sheet.

Stockholders_Equity_StockBased1

Stockholders' Equity, Stock-Based Compensation, Performance Share Units and Noncontrolling Interests (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Common Stock [Table Text Block]	'
	The following is a summary of the changes in our common shares issued for the nine months ended September 30, 2013 and 2012:
			Nine Months Ended
			September 30,
			2013			2012
			(in thousands)
	Shares issued as of January 1		666,468			660,888
	Restricted stock issuances (net of forfeitures)(a)		684			5,758
	Stock option exercises		321			309
	Shares issued as of September 30		667,473			666,955
	___________________________________________
	(a)	In June 2013, we began granting restricted stock units (RSUs) in lieu of restricted stock awards (RSAs) to non-employee directors, and in the Current Quarter, we began granting RSUs in lieu of RSAs to 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 [Table Text Block]	'
	The following reflects the shares outstanding and liquidation preference of our preferred shares for the nine months ended September 30, 2013 and 2012:
			5.75%				5.75% (A)				4.50%				5.00%		Total
															(2005B)
	Shares outstanding as of January 1, 2013		1,497				1,100				2,559				2,096		7,252
	and 2012 and September 30, 2013 and 2012
	(in thousands)
	Liquidation preference per share		$	1,000			$	1,000			$	100			$	100
Stock-Based Compensation [Table Text Block]	'
	We recorded the following stock-based compensation during the Current Quarter, the Prior Quarter, the Current Period and the Prior Period:
			Three Months Ended								Nine Months Ended
			September 30,								September 30,
			2013				2012				2013				2012
			($ in millions)
	Natural gas and oil properties		$	12			$	18			$	45			$	55
	General and administrative expenses		13				17				48				55
	Natural gas, oil and NGL production expenses		5				6				17				18
	Marketing, gathering and compression expenses		2				4				5				12
	Oilfield services expenses		3				2				8				8
	Total		$	35			$	47			$	123			$	148
Restricted Stock [Table Text Block]	'
	A summary of the changes in unvested shares during the nine months ended September 30, 2013 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		9,053			$	19.44
	Vested		(9,553	)		$	23.31
	Forfeited		(1,353	)		$	21.61
	Unvested shares as of September 30, 2013		17,046			$	21.85
Schedule of Share-based Compensation, Stock Options, Activity [Table Text Block]	'
	The following table provides information related to stock option activity for the nine months ended September 30, 2013:
			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		(345	)		$	10.81
	Expired		(94	)		$	19.43
	Outstanding at September 30, 2013		5,306			$	19.27			7.18		$	35
	Exercisable at September 30, 2013		1,386			$	18.79			2.34		$	10
	___________________________________________
	(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 September 30, 2013:
			Units			Fair Value				Fair Value				Liability for
						as of								Vested
						Grant-Date								Amount
						($ in millions)
	2012 Awards (a)
	Payable 2014		278,084			$	8			$	10			$	10
	Payable 2015		834,246			23				29				28
	Total 2012 Awards		1,112,330			$	31			$	39			$	38
	2013 Awards
	Payable 2016		1,637,601			$	37			$	54			$	40
	___________________________________________
	(a)	In the Current Period, we paid $2 million related to 2012 PSU awards.
Distributions Made to Limited Partner, by Distribution [Table Text Block]	'
	For the Current Period and Prior Period, the Trust declared and paid the following distributions:
	Production Period		Distribution Date		Cash Distribution				Cash Distribution
					per				per
					Common Unit				Subordinated Unit
	March 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
	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

Derivative_and_Hedging_Activit1

Derivative and Hedging Activities (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 2013 and December 31, 2012 are provided below.
		30-Sep-13							31-Dec-12
		Volume			Fair Value				Volume			Fair Value
					($ in millions)							($ in millions)
	Natural gas (tbtu):
	Fixed-price swaps	341			$	96			49			$	24
	Call options	193			(219		)		193			(240		)
	Call swaptions	12			—				—			—
	Basis protection swaps	79			(2		)		111			(15		)
	Three-way collars	36			4				—			—
	Total natural gas	661			(121		)		353			(231		)
	Oil (mmbbl):
	Fixed-price swaps	31.6			(94		)		28.1			68
	Call options	65.6			(368		)		73.8			(748		)
	Call swaptions	5.3			(1		)		5.3			(13		)
	Basis protection swaps	0.5			1				5.5			—
	Total oil	103			(462		)		112.7			(693		)
	Total estimated fair value				$	(583	)					$	(924	)
Schedule of Derivative Instruments [Table Text Block]	'
	The components of natural gas, oil and NGL sales for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2013				2012				2013				2012
		($ in millions)
	Natural gas, oil and NGL sales	$	1,839			$	1,464			$	5,303			$	3,798
	Gains (losses) on natural gas, oil and NGL derivatives	(253		)		(27		)		141				824
	Total natural gas, oil and NGL sales	$	1,586			$	1,437			$	5,444			$	4,622
Schedule of Interest Rate Derivatives [Table Text Block]	'
	The notional amount and the estimated fair value of our interest rate derivative liabilities as of September 30, 2013 and December 31, 2012 are provided below.
		30-Sep-13								31-Dec-12
		Notional				Fair				Notional				Fair
		Amount				Value				Amount				Value
						($ in millions)
	Interest rate swaps	$	2,500			$	(88	)		$	1,050			$	(35	)
Interest Income And Interest Expense Disclosure [Table Text Block]	'
	The components of interest expense for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period are presented below.
		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2013				2012				2013				2012
		($ in millions)
	Interest expense on senior notes	$	180			$	187			$	560			$	546
	Interest expense on credit facilities	8				13				30				51
	Interest expense on term loans	29				112				87				173
	(Gains) losses on interest rate derivatives	(3		)		(2		)		51				(4		)
	Amortization of loan discount, issuance costs and other	21				24				70				67
	Capitalized interest	(195		)		(298		)		(634		)		(770		)
	Total interest expense	$	40			$	36			$	164			$	63
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 condensed consolidated balance sheets as of September 30, 2013 and December 31, 2012 on a gross basis without regard to same-counterparty netting:
				Fair Value
		Balance Sheet Location		September 30,				December 31,
				2013				2012
				($ in millions)
	Asset Derivatives:
	Not designated as hedging instruments:
	Commodity contracts	Short-term derivative instruments		$	115			$	110
	Commodity contracts	Long-term derivative instruments		11				5
	Total			126				115
	Liability Derivatives:
	Designated as hedging instruments:
	Foreign currency contracts	Long-term derivative instruments		(5		)		(20		)
	Total			(5		)		(20		)
	Not designated as hedging instruments:
	Commodity contracts	Short-term derivative instruments		(265		)		(157		)
	Commodity contracts	Long-term derivative instruments		(444		)		(882		)
	Interest rate contracts	Short-term derivative instruments		(9		)		—
	Interest rate contracts	Long-term derivative instruments		(79		)		(35		)
	Total			(797		)		(1,074		)
	Total derivative instruments			$	(676	)		$	(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 as of September 30, 2013 and December 31, 2012:
		30-Sep-13
		Derivative Assets								Derivative Liabilities
		Short-				Long-				Short-				Long-
		Term				Term				Term				Term
		($ in millions)
	Commodity Contracts:
	Gross amounts of recognized assets (liabilities)	$	115			$	11			$	(265	)		$	(444	)
	Gross amounts offset in the condensed consolidated	(104		)		(9		)		104				9
	balance sheet
	Net amounts of assets (liabilities) presented in the	11				2				(161		)		(435		)
	condensed consolidated balance sheet
	Interest Rate Contracts:
	Gross amounts of recognized assets (liabilities)	—				—				(9		)		(79		)
	Gross amounts offset in the condensed consolidated	—				—				—				—
	balance sheet
	Net amounts of assets (liabilities) presented in the	—				—				(9		)		(79		)
	condensed consolidated balance sheet
	Foreign Currency Contracts:
	Gross amounts of recognized assets (liabilities)	—				—				—				(5		)
	Gross amounts offset in the condensed consolidated	—				—				—				—
	balance sheet
	Net amounts of assets (liabilities) presented in the	—				—				—				(5		)
	condensed consolidated balance sheet
	Total derivatives as reported	$	11			$	2			$	(170	)		$	(519	)
		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	58				2				(105		)		(879		)
	consolidated balance sheet
	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	—				—				—				(35		)
	consolidated balance sheet
	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	—				—				—				(20		)
	consolidated balance sheet
	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 the condensed consolidated statements of operations for terminated instruments that were designated as fair value derivatives:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
	Fair Value Derivatives	Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
	Interest rate contracts	Interest expense		$	1			$	2			$	4			$	6
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	'
	Accumulated Other Comprehensive Income (Loss)
	For the Current Period, changes in accumulated other comprehensive income (loss) by component, net of tax, are detailed below.
		Net Gains				Net Gains				Total
		(Losses) on				(Losses)
		Cash Flow				on
		Hedges				Investments
		($ in millions)
	Balance, December 31, 2012	$	(189	)		$	7			$	(182	)
	Other comprehensive income before reclassifications	2				(6		)		(4		)
	Amounts reclassified from accumulated other comprehensive income	13				4				17
	Net current period other comprehensive income	15				(2		)		13
	Balance, September 30, 2013	$	(174	)		$	5			$	(169	)
	A reconciliation of the changes of accumulated other comprehensive income (loss) in the condensed consolidated statements of stockholders’ equity related to our cash flow hedges is presented below.
		Three Months Ended
		September 30,
		2013								2012
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
	Balance, beginning of period	$	(286	)		$	(178	)		$	(306	)		$	(190	)
	Net change in fair value	3				2				4				3
	(Gains) losses reclassified to income	3				2				(9		)		(6		)
	Balance, end of period	$	(280	)		$	(174	)		$	(311	)		$	(193	)
		Nine Months Ended
		September 30,
		2013								2012
		Before				After				Before				After
		Tax				Tax				Tax				Tax
		($ in millions)
	Balance, beginning of period	$	(304	)		$	(189	)		$	(287	)		$	(178	)
	Net change in fair value	3				2				4				3
	(Gains) losses reclassified to income	21				13				(28		)		(18		)
	Balance, end of period	$	(280	)		$	(174	)		$	(311	)		$	(193	)
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:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
	Cash Flow Derivatives	Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
	Gain (Loss) Recognized in AOCI (Effective Portion):
	Foreign currency	AOCI		$	3			$	4			$	3			$	4
	contracts
				$	3			$	4			$	3			$	4
	Gain (Loss) Reclassified from AOCI (Effective Portion):
	Commodity	Natural gas, oil and		$	(3	)		$	9			$	(21	)		$	28
	contracts	NGL sales
				$	(3	)		$	9			$	(21	)		$	28
Derivatives Not Designated As Hedging Instruments Disclosure [Table Text Block]	'
	The following table presents the gain (loss) recognized in the condensed consolidated statements of operations for instruments not designated as either cash flow or fair value hedges:
				Three Months Ended								Nine Months Ended
				September 30,								September 30,
	Derivative Contracts	Location of Gain (Loss)		2013				2012				2013				2012
				($ in millions)
	Commodity contracts	Natural gas, oil and		$	(250	)		$	(36	)		$	162			$	796
		NGL sales
	Interest rate contracts	Interest expense		2				—				(55		)		(2		)
	Total			$	(248	)		$	(36	)		$	107			$	794

Divestitures_Tables

Divestitures (Tables)	9 Months Ended
	Sep. 30, 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		Sinopec	Jun-13		50.00%		$	949		(d)	$	—		$	949		$	—
	Lime
	Utica		TOT	December 2011		25.00%		610				1,422		(e)	2,032			714
	Niobrara		CNOOC	Feb-11		33.30%		570				697		(f)	1,267			233
	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		$	947
	____________________________________________
	(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 September 30, 2013.
	(d)	Excludes $71 million of net proceeds (or 7% of the total transaction) expected to be received pursuant to certain customary post-closing adjustments and approximately $90 million received at closing for closing adjustments.
	(e)	The Utica drilling carries cover 60% of our drilling and completion costs for Utica wells drilled and must be used by December 2018. We expect to fully utilize these drilling carry commitments prior to expiration. See Note 4 for further discussion of the Utica drilling carries.
	(f)	The Niobrara drilling carries cover 67% of our drilling and completion costs for Niobrara wells drilled and must be used by December 2014. We expect to fully utilize these drilling carry commitments prior to expiration.
VPP Transactions [Table Text Block]	'
	Our outstanding VPPs consist of the following:
										Volume Sold
	VPP #		Date of VPP	Division		Proceeds				Natural Gas			Oil		NGL		Total
						($ 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 for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period were as follows:
			Three Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		3.7		131			371.9			6.7
	9		4.1		52.3			140.3			5.2
	8		16.6		—			—			16.6
	6		1.2		6			—			1.2
	5		1.9		6.7			—			1.9
	4		2.4		13.9			—			2.6
	3		2		—			—			2
	2		2.6		—			—			2.6
	1		3.5		—			—			3.5
			38		209.9			512.2			42.3
			Three Months Ended September 30, 2012
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		5.3		206			503.7			9.5
	9		4.5		60.8			158			5.8
	8		19.4		—			—			19.4
	7		0.2		147.3			—			1
	6		1.3		6			—			1.4
	5		2.2		6.6			—			2.2
	4		2.9		15.8			—			3
	3		2.3		—			—			2.3
	2		2.8		—			—			2.8
	1		3.7		—			—			3.7
			44.6		442.5			661.7			51.1
			Nine Months Ended September 30, 2013
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		11.4		426			1,158.60			20.9
	9		12.5		162.5			433			16
	8		51.6		—			—			51.6
	6		3.6		18			—			3.7
	5		5.7		19			—			5.8
	4		7.8		42.7			—			8.1
	3		6.2		—			—			6.2
	2		7.9		—			—			7.9
	1		10.9		—			—			10.9
			117.6		668.2			1,591.60			131.1
			Nine Months Ended September 30, 2012
	VPP #		Natural Gas		Oil			NGL			Total
			(bcf)		(mbbl)			(mbbl)			(bcfe)
	10		13.5		547			1,286.60			24.5
	9		14		191			490.6			18.1
	8		61.1		—			—			61.1
	7		0.4		490.3			—			3.4
	6		4.1		18			—			4.2
	5		6.8		21.2			—			6.9
	4		9		48.7			—			9.3
	3		7.1		—			—			7.1
	2		8.6		—			—			8.6
	1		11.5		—			—			11.5
			136.1		1,316.20			1,777.20			154.7
VPP Volumes Remaining to be Delivered [Table Text Block]	'
	The volumes remaining to be delivered on behalf of our VPP buyers as of September 30, 2013 were as follows:
				Volume Remaining as of September 30, 2013
	VPP #		Term Remaining	Natural Gas			Oil			NGL			Total
			(in months)	(bcf)			(mmbbl)			(mmbbl)			(bcfe)
	10		101	57.1			1.8			6.3			106.1
	9		89	89.5			1.1			3.1			114.4
	8		23	112			—			—			112
	6		76	22.6			0.2			—			23.6
	5		40	18.7			0.1			—			19
	4		39	27.2			0.1			—			28.1
	3		70	33			—			—			33
	2		67	23.1			—			—			23.1
	1		111	109			—			—			109
				492.2			3.3			9.4			568.3

Investments_Tables

Investments (Tables)	9 Months Ended
	Sep. 30, 2013
Text Block [Abstract]	'
Schedule Of Investments [Table Text Block]	'
	A summary of our investments, including our approximate ownership percentage as of September 30, 2013, is presented below.
				Carrying Value
		Approximate	Accounting	September 30,		December 31,
		Ownership %	Method	2013		2012
				($ in millions)
	FTS International, Inc.	30%	Equity	$	318	$	298
	Chaparral Energy, Inc.	20%	Equity	145		141
	Sundrop Fuels, Inc.	50%	Equity	97		111
	Twin Eagle Resource Management, LLC	30%	Equity	30		34
	Maalt Specialized Bulk, LLC	49%	Equity	13		13
	Clean Energy Fuels Corp.	—	Fair Value	—		12
	(common stock)
	Clean Energy Fuels Corp.	—	Cost	—		100
	(convertible notes)
	Gastar Exploration Ltd.	—	Fair Value	—		8
	Other	—	—	12		11
	Total investments			$	615	$	728

Net_Gains_Losses_on_Sales_of_F1

Net Gains (Losses) on Sales of Fixed Assets (Tables)	9 Months Ended
	Sep. 30, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Table Text Block]	'
	A summary of our gains or losses by asset class for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended						Nine Months Ended
		September 30,						September 30,
		2013			2012			2013			2012
		($ in millions)
	Gathering systems and treating plants	$	(132	)	$	(7	)	$	(311	)	$	(8	)
	Drilling rigs and equipment	—			10			1			12
	Buildings and land	1			—			24			—
	Other	(1		)	4			(4		)	1
	Total net (gains) losses on sales of fixed assets	$	(132	)	$	7		$	(290	)	$	5

Impairments_Tables

Impairments (Tables)	9 Months Ended
	Sep. 30, 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 Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		($ in millions)
	Buildings and land	$	8	$	7	$	247	$	227
	Drilling rigs and equipment	24		31		27		54
	Gathering systems	21		—		22		—
	Other	32		—		47		—
	Total impairments of fixed assets and other	$	85	$	38	$	343	$	281

Recovered_Sheet1

Restructuring and other Termination Benefits (Tables)	9 Months Ended
	Sep. 30, 2013
Restructuring and Related Activities [Abstract]	'
Restructuring and Related Costs [Table Text Block]	'
	Substantially all of the restructuring and other termination benefits in the Current Period are in the exploration and production operating segment. A summary of our restructuring and other termination benefits for the Current Quarter, the Prior Quarter, the Current Period and the Prior Period is as follows:
		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2013		2012		2013		2012
		($ in millions)
	Restructuring charges under workforce reduction plan:
	Salary expense	$	5	$	—	$	5	$	—
	Acceleration of stock-based compensation	25		—		25		—
	Other termination benefits	1		—		1		—
	Total restructuring charges	31		—		31		—
	under workforce reduction plan
	Termination benefits provided to Mr. McClendon:
	Salary and bonus expense	—		—		11		—
	Acceleration of 2008 performance bonus	—		—		11		—
	“claw-back” feature
	Acceleration of stock-based compensation	—		—		22		—
	Acceleration of performance share unit awards	3		—		16		—
	Estimated aircraft usage benefits	—		—		7		—
	Total termination benefits provided to	3		—		67		—
	Mr. McClendon
	Termination benefits provided to VSP participants:
	Salary and bonus expense	—		—		33		—
	Acceleration of stock-based compensation	1		—		28		—
	Other termination benefits	—		—		2		—
	Total termination benefits provided to	1		—		63		—
	VSP participants
	Other termination benefits	28		3		42		4
	Total restructuring and other termination benefits	$	63	$	3	$	203	$	4

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 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 September 30, 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		$	93		$	—		$	—		$	93
	Other current liabilities		(89		)	—			—			(89		)
	Derivatives:
	Commodity assets		—			105			21			126
	Commodity liabilities		—			(103		)	(606		)	(709		)
	Interest rate liabilities		—			(88		)	—			(88		)
	Foreign currency liabilities		—			(5		)	—			(5		)
	Total derivatives		—			(91		)	(585		)	(676		)
	Total		$	4		$	(91	)	$	(585	)	$	(672	)
	The following table provides fair value measurement information for financial assets (liabilities) measured at fair value on a recurring basis 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 the Current Period and the Prior Period 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)		338			(1		)
	Total purchases, issuances, sales and settlements:
	Sales		—			1
	Settlements		93			—
	Ending Balance as of September 30, 2013		$	(585	)	$	—
	Beginning Balance as of January 1, 2012		$	(1,654	)	$	—
	Total gains (losses) (realized/unrealized):
	Included in earnings(a)		525			4
	Total purchases, issuances, sales and settlements:
	Sales		—			(6		)
	Settlements		56			—
	Ending Balance as of September 30, 2012		$	(1,073	)	$	(2	)
	___________________________________________
	(a)		Natural Gas, Oil and						Interest Expense
			NGL Sales
			2013			2012			2013			2012
			($ in millions)
	Total gains (losses) included in earnings for the period		$	338		$	525		$	(1	)	$	4
	Change in unrealized gains (losses) relating to assets still held at reporting date		$	327		$	370		$	—		$	(2	)
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			September 30,
									2013
									($ in millions)
	Oil Trades(a)		Oil price volatility curves		9.94% - 25.79%	16.44		%	$	(369	)
	Oil Basis Swaps(b)		Physical pricing point forward		$3.03 - $4.65	$	4.33		$	1
			curves
	Natural Gas Trades(a)		Natural gas price volatility		20.08% - 34.86%	22.1		%	$	(215	)
			curves
	Natural Gas Basis Swaps(b)		Physical pricing point forward		($1.64) - $0	$	(0.36	)	$	(2	)
			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.
			30-Sep-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)		$	10,470		$	11,333		$	9,759		$	10,457
	Long-term debt (Level 2)		$	2,252		$	2,241		$	2,378		$	2,284

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 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)
	Three Months Ended
	September 30, 2013:
	Revenues	$	1,586		$	5,034		$	551		$	4		$	(2,308	)	$	4,867
	Intersegment revenues	—			(2,002		)	(306		)	—			2,308			—
	Total revenues	$	1,586		$	3,032		$	245		$	4		$	—		$	4,867
	Income (Loss) Before	$	430		$	128		$	(37	)	$	(48	)	$	(86	)	$	387
	Income Taxes
	Three Months Ended
	September 30, 2012:
	Revenues	$	1,437		$	2,922		$	482		$	—		$	(1,871	)	$	2,970
	Intersegment revenues	—			(1,541		)	(330		)	—			1,871			—
	Total revenues	$	1,437		$	1,381		$	152		$	—		$	—		$	2,970
	Income (Loss) Before	$	(3,073	)	$	120		$	(2	)	$	(152	)	$	(124	)	$	(3,231	)
	Income Taxes
	Nine Months Ended
	September 30, 2013:
	Revenues	$	5,444		$	12,553		$	1,677		$	27		$	(6,736	)	$	12,965
	Intersegment revenues	—			(5,682		)	(1,041		)	(13		)	6,736			—
	Total revenues	$	5,444		$	6,871		$	636		$	14		$	—		$	12,965
	Income (Loss) Before	$	654		$	395		$	(12	)	$	808		$	(284	)	$	1,561
	Income Taxes
	Nine Months Ended
	September 30, 2012:
	Revenues	$	4,622		$	7,587		$	1,434		$	—		$	(4,865	)	$	8,778
	Intersegment revenues	—			(3,877		)	(988		)	—			4,865			—
	Total revenues	$	4,622		$	3,710		$	446		$	—		$	—		$	8,778
	Income (Loss) Before	$	(1,896	)	$	1,279		$	96		$	(654	)	$	(362	)	$	(1,537	)
	Income Taxes
	As of
	September 30, 2013:
	Total Assets	$	35,919		$	2,323		$	1,981		$	5,014		$	(2,949	)	$	42,288
	As of
	December 31, 2012:
	Total Assets	$	37,004		$	2,291		$	2,115		$	2,529		$	(2,328	)	$	41,611

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	9 Months Ended
	Sep. 30, 2013
Condensed Financial Information of Parent Company Only Disclosure [Abstract]	'
Schedule of Condensed Balance Sheet [Table Text Block]	'
	CONDENSED CONSOLIDATING BALANCE SHEET
	AS OF SEPTEMBER 30, 2013
	($ in millions)
			Parent			Guarantor			Non-Guarantor			Eliminations			Consolidated
						Subsidiaries			Subsidiaries
	CURRENT ASSETS:
	Cash and cash equivalents		$	966		$	—		$	14		$	7		$	987
	Restricted cash		—			—			82			(7		)	75
	Other		104			2,606			645			(423		)	2,932
	Current assets held for sale		—			—			—			—			—
	Intercompany receivable, net		25,863			—			—			(25,863		)	—
	Total Current Assets		26,933			2,606			741			(26,286		)	3,994
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,245			3,123			151			32,519
	Other property and equipment, net		—			2,561			1,445			(1		)	4,005
	Property and equipment held for sale, net		—			571			26			—			597
	Total Property and Equipment,		—			32,377			4,594			150			37,121
	Net
	LONG-TERM ASSETS:
	Other assets		114			1,316			115			(372		)	1,173
	Investments in subsidiaries and		2,211			(238		)	—			(1,973		)	—
	intercompany advances
	TOTAL ASSETS		$	29,258		$	36,061		$	5,450		$	(28,481	)	$	42,288
	CURRENT LIABILITIES:
	Current liabilities		$	242		$	5,427		$	431		$	(422	)	$	5,678
	Intercompany payable, net		—			24,740			1,279			(26,019		)	—
	Total Current Liabilities		242			30,167			1,710			(26,441		)	5,678
	LONG-TERM LIABILITIES:
	Long-term debt, net		11,801			—			935			—			12,736
	Deferred income tax liabilities		638			2,397			60			328			3,423
	Other long-term liabilities		381			1,286			900			(464		)	2,103
	Total Long-Term Liabilities		12,820			3,683			1,895			(136		)	18,262
	EQUITY:
	Chesapeake stockholders’ equity		16,196			2,211			1,845			(4,056		)	16,196
	Noncontrolling interests		—			—			—			2,152			2,152
	Total Equity		16,196			2,211			1,845			(1,904		)	18,348
	TOTAL LIABILITIES AND EQUITY		$	29,258		$	36,061		$	5,450		$	(28,481	)	$	42,288
	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			2,378			512			(345		)	2,546
	Current assets held for sale		—			—			4			—			4
	Intercompany receivable, net		25,356			—			—			(25,356		)	—
	Total Current Assets		25,585			2,378			686			(25,701		)	2,948
	PROPERTY AND EQUIPMENT:
	Natural gas and oil properties, at cost based on full cost accounting, net		—			29,083			3,057			(222		)	31,918
	Other property and equipment, net		—			3,066			1,549			—			4,615
	Property and equipment held for sale, net		—			255			379			—			634
	Total Property and Equipment,		—			32,404			4,985			(222		)	37,167
	Net
	LONG-TERM ASSETS:
	Other assets		217			1,396			261			(378		)	1,496
	Investments in subsidiaries and		2,241			(186		)	—			(2,055		)	—
	intercompany advances
	TOTAL ASSETS		$	28,043		$	35,992		$	5,932		$	(28,356	)	$	41,611
	CURRENT LIABILITIES:
	Current liabilities		$	789		$	5,377		$	424		$	(345	)	$	6,245
	Current liabilities held for sale		—			—			21			—			21
Intercompany payable, net		—			24,166			1,312			(25,478		)	—
Total Current Liabilities		789			29,543			1,757			(25,823		)	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			2,241			2,141			(4,382		)	15,569
Noncontrolling interests		—			—			—			2,327			2,327
Total Equity		15,569			2,241			2,141			(2,055		)	17,896
TOTAL LIABILITIES AND EQUITY		$	28,043		$	35,992		$	5,932		$	(28,356	)	$	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 $228 million, which was incorrectly presented in the Guarantor subsidiaries as of December 31, 2012. The impact of this error was not material to any previously issued financial statements.
Schedule of Condensed Income Statement [Table Text Block]	'
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED SEPTEMBER 30, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	1,400		$	185		$	1		$	1,586
	Marketing, gathering and compression		—			3,031			1			—			3,032
	Oilfield services		—			—			552			(303		)	249
	Total Revenues		—			4,431			738			(302		)	4,867
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			268			14			—			282
	Production taxes		—			60			2			—			62
	Marketing, gathering and compression		—			3,009			—			—			3,009
	Oilfield services		—			23			460			(272		)	211
	General and administrative		—			97			24			(1		)	120
	Restructuring and other termination benefits		—			63			—			—			63
	Natural gas, oil and NGL depreciation,		—			591			61			—			652
	depletion and amortization
	Depreciation and amortization of other		—			43			74			(38		)	79
	assets
	Impairment of natural gas and oil		—			—			99			(99		)	—
	properties
	Impairments of fixed assets and other		—			56			29			—			85
	Net (gains) losses on sales of		—			(133		)	—			1			(132		)
	fixed assets
	Total Operating Expenses		—			4,077			763			(409		)	4,431
	INCOME (LOSS) FROM OPERATIONS		—			354			(25		)	107			436
	OTHER INCOME (EXPENSE):
	Interest expense		(207		)	(27		)	(21		)	215			(40		)
	Losses on investments		—			(22		)	—			—			(22		)
	Impairment of investment		—			—			(1		)	1			—
	Gains (losses) on sales of investments		—			3			—			—			3
	Other income (expense)		208			44			2			(244		)	10
	Equity in net earnings of subsidiary		201			(75		)	—			(126		)	—
	Total Other Income (Expense)		202			(77		)	(20		)	(154		)	(49		)
	INCOME (LOSS) BEFORE INCOME		202			277			(45		)	(47		)	387
	TAXES
	INCOME TAX EXPENSE (BENEFIT)		—			134			(17		)	30			147
	NET INCOME (LOSS)		202			143			(28		)	(77		)	240
	Net income attributable to		—			—			—			(38		)	(38		)
	noncontrolling interests
	NET INCOME (LOSS) ATTRIBUTABLE		202			143			(28		)	(115		)	202
	TO CHESAPEAKE
	Other comprehensive income (loss)		2			1			(2		)	—			1
	COMPREHENSIVE INCOME (LOSS)		$	204		$	144		$	(30	)	$	(115	)	$	203
	ATTRIBUTABLE TO CHESAPEAKE
	CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
	THREE MONTHS ENDED SEPTEMBER 30, 2012
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	REVENUES:
	Natural gas, oil and NGL		$	—		$	1,357		$	79		$	1		$	1,437
	Marketing, gathering and compression		—			1,319			62			—			1,381
	Oilfield services		—			—			485			(333		)	152
	Total Revenues		—			2,676			626			(332		)	2,970
	OPERATING EXPENSES:
	Natural gas, oil and NGL production		—			311			9			—			320
	Production taxes		—			51			2			—			53
	Marketing, gathering and compression		—			1,310			29			—			1,339
Oilfield services		—			80			361			(325		)	116
General and administrative		—			108			37			—			145
Restructuring and other termination benefits		—			2			1			—			3
Natural gas, oil and NGL depreciation,		—			716			46			—			762
depletion and amortization
Depreciation and amortization of other		—			43			58			(35		)	66
assets
Impairment of natural gas and oil properties		—			3,167			148			—			3,315
Impairments of fixed assets and other		—			8			30			—			38
Net (gains) losses on sales of		—			4			3			—			7
fixed assets
Total Operating Expenses		—			5,800			724			(360		)	6,164
INCOME (LOSS) FROM OPERATIONS		—			(3,124		)	(98		)	28			(3,194		)
OTHER INCOME (EXPENSE):
Interest expense		(289		)	(18		)	(21		)	292			(36		)
Losses on investments		—			(23		)	—			—			(23		)
Gains (losses) on sales of investments		—			—			31			—			31
Other income (expense)		286			79			3			(377		)	(9		)
Equity in net earnings (losses) of subsidiary		(2,010		)	(127		)	—			2,137			—
Total Other Income (Expense)		(2,013		)	(89		)	13			2,052			(37		)
INCOME (LOSS) BEFORE INCOME		(2,013		)	(3,213		)	(85		)	2,080			(3,231		)
TAXES
INCOME TAX EXPENSE (BENEFIT)		(1		)	(1,204		)	(33		)	(22		)	(1,260		)
NET INCOME (LOSS)		(2,012		)	(2,009		)	(52		)	2,102			(1,971		)
Net income attributable to		—			—			—			(41		)	(41		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(2,012		)	(2,009		)	(52		)	2,061			(2,012		)
TO CHESAPEAKE
Other comprehensive income (loss)		3			(7		)	(2		)	—			(6		)
COMPREHENSIVE INCOME (LOSS)		$	(2,009	)	$	(2,016	)	$	(54	)	$	2,061		$	(2,018	)
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2013
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,962		$	473		$	9		$	5,444
Marketing, gathering and compression		—			6,861			10			—			6,871
Oilfield services		—			—			1,703			(1,053		)	650
Total Revenues		—			11,823			2,186			(1,044		)	12,965
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			838			39			—			877
Production taxes		—			167			6			—			173
Marketing, gathering and compression		—			6,776			5			—			6,781
Oilfield services		—			70			1,362			(889		)	543
General and administrative		—			264			73			(1		)	336
Restructuring and other termination benefits		—			200			3			—			203
Natural gas, oil and NGL depreciation,		—			1,771			174			—			1,945
depletion and amortization
Depreciation and amortization of other		—			137			218			(121		)	234
assets
Impairment of natural gas and oil		—			—			260			(260		)	—
properties
Impairments of fixed assets and other		—			307			36			—			343
Net gains (losses) on sales of		—			(291		)	—			1			(290		)
fixed assets
Total Operating Expenses		—			10,239			2,176			(1,270		)	11,145
INCOME (LOSS) FROM OPERATIONS		—			1,584			10			226			1,820
OTHER INCOME (EXPENSE):
Interest expense		(703		)	(70		)	(63		)	672			(164		)
Losses on investments		—			(26		)	—			—			(26		)
Impairment of investment		—			(10		)	(1		)	1			(10		)
Gains (losses) on sales of investments		—			(7		)	—			—			(7		)
Losses on purchases of debt		(70		)	—			—			—			(70		)
Other income (expense)		651			120			7			(760		)	18
Equity in net earnings of subsidiary		916			(221		)	—			(695		)	—
Total Other Income (Expense)		794			(214		)	(57		)	(782		)	(259		)
INCOME (LOSS) BEFORE INCOME TAXES		794			1,370			(47		)	(556		)	1,561
INCOME TAX EXPENSE (BENEFIT)		(46		)	605			(18		)	53			594
NET INCOME (LOSS)		840			765			(29		)	(609		)	967
Net income attributable to		—			—			—			(127		)	(127		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		840			765			(29		)	(736		)	840
TO CHESAPEAKE
Other comprehensive income		2			12			(1		)	—			13
COMPREHENSIVE INCOME (LOSS)		$	842		$	777		$	(30	)	$	(736	)	$	853
ATTRIBUTABLE TO CHESAPEAKE
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 2012
($ in millions)
		Parent			Guarantor			Non-			Eliminations			Consolidated
					Subsidiaries			Guarantor
								Subsidiaries
REVENUES:
Natural gas, oil and NGL		$	—		$	4,410		$	209		$	3		$	4,622
Marketing, gathering and compression		—			3,555			155			—			3,710
Oilfield services		—			—			1,440			(994		)	446
Total Revenues		—			7,965			1,804			(991		)	8,778
OPERATING EXPENSES:
Natural gas, oil and NGL production		—			989			16			—			1,005
Production taxes		—			137			4			—			141
Marketing, gathering and compression		—			3,549			82			—			3,631
Oilfield services		—			141			1,029			(849		)	321
General and administrative		—			343			93			—			436
Restructuring and other termination benefits		—			3			1			—			4
Natural gas, oil and NGL depreciation,		—			1,761			95			—			1,856
depletion and amortization
Depreciation and amortization of other		—			132			205			(104		)	233
assets
Impairment of natural gas and oil		—			3,167			148			—			3,315
properties
Impairment of fixed assets and other		—			227			54			—			281
Net (gains) losses on sales of		—			2			3			—			5
fixed assets
Total Operating Expenses		—			10,451			1,730			(953		)	11,228
INCOME (LOSS) FROM OPERATIONS		—			(2,486		)	74			(38		)	(2,450		)
OTHER INCOME (EXPENSE):
Interest expense		(682		)	(3		)	(64		)	686			(63		)
Earnings (losses) on investments		—			(142		)	55			—			(87		)
Gains on sales of investments		—			1,030			31			—			1,061
Other income (expense)		667			166			10			(841		)	2
Equity in net earnings (losses) of subsidiary		(1,060		)	(179		)	—			1,239			—
Total Other Income (Expense)		(1,075		)	872			32			1,084			913
INCOME (LOSS) BEFORE INCOME TAXES		(1,075		)	(1,614		)	106			1,046			(1,537		)
INCOME TAX EXPENSE (BENEFIT)		(6		)	(559		)	41			(75		)	(599		)
NET INCOME (LOSS)		(1,069		)	(1,055		)	65			1,121			(938		)
Net income attributable to		—			—			—			(131		)	(131		)
noncontrolling interests
NET INCOME (LOSS) ATTRIBUTABLE		(1,069		)	(1,055		)	65			990			(1,069		)
TO CHESAPEAKE
Other comprehensive income (loss)		3			(25		)	—			—			(22		)
COMPREHENSIVE INCOME (LOSS)		$	(1,066	)	$	(1,080	)	$	65		$	990		$	(1,091	)
ATTRIBUTABLE TO CHESAPEAKE
Schedule of Condensed Cash Flow Statement [Table Text Block]	'
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	NINE MONTHS ENDED SEPTEMBER 30, 2013
	($ in millions)
			Parent			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING		$	—		$	3,232		$	362		$	(33	)	$	3,561
	ACTIVITIES
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Additions to proved and unproved		—			(4,642		)	(639		)	—			(5,281		)
	properties
	Proceeds from divestitures of proved		—			2,736			53			—			2,789
	and unproved properties
	Additions to other property and		—			(415		)	(224		)	—			(639		)
	equipment
	Other investing activities		—			67			757			260			1,084
	Net Cash Used In Investing Activities		—			(2,254		)	(53		)	260			(2,047		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facilities		—			6,311			825			—			7,136
	borrowings
	Payments on credit facilities borrowings		—			(6,310		)	(958		)	—			(7,268		)
	Proceeds from issuance of senior notes,		2,274			—			—			—			2,274
	net of discount and offering costs
	Cash paid to purchase debt		(2,116		)	—			—			—			(2,116		)
	Proceeds from sales of noncontrolling		—			5			—			—			5
	interests
	Other financing activities		(374		)	(297		)	46			(220		)	(845		)
	Intercompany advances, net		954			(687		)	(267		)	—			—
	Net Cash Provided By (Used In) Financing Activities		738			(978		)	(354		)	(220		)	(814		)
	Net increase (decrease) in cash and cash		738			—			(45		)	7			700
	equivalents
	Cash and cash equivalents, beginning of		228			—			59			—			287
	period
	Cash and cash equivalents, end of period		$	966		$	—		$	14		$	7		$	987
	CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
	NINE MONTHS ENDED SEPTEMBER 30, 2012
	($ in millions)
			Parent(a)			Guarantor			Non-			Eliminations			Consolidated
						Subsidiaries(a)			Guarantor
									Subsidiaries
	CASH FLOWS FROM OPERATING ACTIVITIES		$	—		$	2,779		$	200		$	(1,001	)	$	1,978
	CASH FLOWS FROM INVESTING
	ACTIVITIES:
	Additions to proved and unproved		—			(10,208		)	(130		)	—			(10,338		)
	properties
	Proceeds from divestitures of proved		—			2,445			—			—			2,445
	and unproved properties
	Additions to other property and		—			(577		)	(1,339		)	—			(1,916		)
	equipment
	Other investing activities		—			3,051			(158		)	(1,238		)	1,655
	Net Cash Used In Investing Activities		—			(5,289		)	(1,627		)	(1,238		)	(8,154		)
	CASH FLOWS FROM FINANCING ACTIVITIES:
	Proceeds from credit facilities borrowings		—			12,116			1,870			—			13,986
	Payments on credit facilities borrowings		—			(12,051		)	(1,563		)	—			(13,614		)
	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		3,789			—			—			—			3,789
	Proceeds from sales of noncontrolling interests		—			—			1,056			—			1,056
	Other financing activities		(367		)	(154		)	(2,217		)	2,239			(499		)
	Intercompany advances, net		(4,618		)	2,599			2,019			—			—
	Net Cash Provided By Financing Activities		67			2,510			1,165			2,239			5,981
	Change in cash and cash equivalents		(7		)	—			(7		)	—			(14		)
	classified as current assets held for sale
Net increase in cash and cash equivalents		60			—			(269		)	—			(209		)
Cash and cash equivalents, beginning of		1			—			350			—			351
period
Cash and cash equivalents, end of period		$	61		$	—		$	81		$	—		$	142
___________________________________________
(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 $61 million, which was incorrectly presented as the Guarantor subsidiaries as of September 30, 2012. 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 Assets Held for Sale Table (Details) (USD $)	Sep. 30, 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	597	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	242	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	10	352
Exploration and Production Equipment [Member]	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	26	27
Property, Plant and Equipment, Other Types	'	'
Long Lived Assets Held-for-sale [Line Items]	'	'
Property and equipment held for sale, net	319	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

Basis_of_Presentation_and_Summ4

Basis of Presentation and Summary of Significant Accounting Policies AOCI Changes Net of Tax Table (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Accumulated Net Unrealized Investment Gain (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 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)

'

$5

'

'

($182)

'

($189)

'

$7

Other comprehensive income before reclassifications

'

'

'

'

'

'

-4

'

2

'

-6

'

Amounts reclassified from accumulated other comprehensive income

'

'

'

'

'

0

17

17

13

'

4

'

Net current period other comprehensive income

1

-6

13

-22

'

'

'

13

'

15

'

-2

AOCI (Loss), Net of Tax - Period End

($169)

'

($169)

'

$5

'

'

'

'

($174)

'

'

Basis_of_Presentation_and_Summ5

Basis of Presentation and Summary of Significant Accounting Policies AOCI Reclassified Table (Details) (Accumulated Other Comprehensive Income (Loss) [Member], USD $)	3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 29, 2013	Sep. 30, 2013
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	$0	$17	$17
Natural Gas, Oil and NGL Revenue [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	2	'	13
Impairment of Investment [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	'	6
Sale of Investment [Member]	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	($2)	'	($2)

Basis_of_Presentation_and_Summ6

Basis of Presentation and Summary of Significant Accounting Policies - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended	9 Months Ended	12 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
					Mcfe	Scenario, Forecast, Remaining 2013 [Member]	Scenario, Forecast [Member]	Scenario, Forecast [Member]	Scenario, Forecast [Member]	Scenario, Forecast [Member]	Corporate Revolving Bank Credit Facility
						Oil [Member]		Natural Gas [Member]	Natural Gas [Member]	Oil [Member]
								Mcf	Mcf	Boe
Concentration Risk [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Spending Gap	'	'	'	'	'	'	$3,500,000,000	'	'	'	'
Borrowing capacity	'	'	'	'	'	'	'	'	'	'	4,000,000,000
Percentage Of Proved Reserve Volumes That Are Natural Gas	'	'	'	'	70.00%	'	'	'	'	'	'
Natural Gas Percent Of Sales	73.00%	'	'	'	80.00%	'	'	'	'	'	'
Percentage of Hedged Production	'	'	'	'	'	'	'	80.00%	80.00%	91.00%	'
Hedged Price	'	'	'	'	'	95.59	'	4.22	3.69	93.79	'
Proved Developed Reserves (Energy)	'	'	'	'	'	'	'	'	'	22	'
Proved Developed Reserves (Volume)	'	'	'	'	'	'	'	251	251	'	'
Additional Proved Developed And Undeveloped Reserves Revisions Of Previous Estimates Increase Decrease	'	'	'	'	3,100,000,000,000	'	'	'	'	'	'
Additional Proved Developed And Undeveloped Reserve Revisions of Previous Estimates, Percentage Increase or Decrease	'	'	'	'	17.00%	'	'	'	'	'	'
Impairment of natural gas and oil properties	$0	$3,315,000,000	$0	$3,315,000,000	'	'	'	'	'	'	'

Earnings_Per_Share_Antidilutiv

Earnings Per Share - Antidilutive Securities Excluded from Computation of EPS Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Convertible Debt Securities [Member] | 5.75% Cumulative Convertible Preferred Stock	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	$21	$21	$64	$64
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	56	56	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	16	16	47	47
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	39	39	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	3	3	8	8
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	5	5	5	5
Convertible Debt Securities [Member] | 4.50% Cumulative Comvertible Preferred Stock [Member]	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	3	3	9	9
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	6	6	6	6
Restricted stock	'	'	'	'
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]	'	'	'	'
Net Income Adjustments	$3	$0	$14	$0
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	2	3	3	4

Debt_LongTerm_Debt_Table_Detai

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

9 Months Ended

9 Months Ended

In Millions, except Per Share data, unless otherwise specified

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2006

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

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

Discount On Senior Notes

Discount On Senior Notes

Interest rate contract

Interest rate contract

Foreign currency contracts

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

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Revolving Credit Facility [Member]

Senior Secured Term Loan Due Two Thousand And Seventeen [Member]

Senior Secured Term Loan Due Two Thousand And Seventeen [Member]

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

6.5% 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

Corporate Revolving Bank Credit Facility

Corporate Revolving Bank Credit Facility

Oilfield Services Revolving Bank Credit Facility

Oilfield Services Revolving Bank Credit Facility

Cross Currency Interest Rate Contract [Member]

Cross Currency Interest Rate Contract [Member]

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Gross

$12,736

$12,620

'

'

'

'

'

($380)

($465)

$14

$20

'

$2,000

$2,000

'

'

$0

$464

$1,265

$1,265

$500

$0

$465

$454

$465

'

$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

$0

$0

$285

$418

Current maturities of long-term debt, net

0

-463

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt, Excluding Current Maturities

12,736

12,157

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Discount

'

'

'

'

'

'

'

'

'

'

'

'

$34

$40

$322

$376

'

$1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Forward Exchange Rate

'

'

'

'

'

'

'

'

'

'

'

1.3193

'

'

'

'

'

'

'

'

'

'

'

'

1.3527

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

'

'

'

'

$48.31

$63.62

$107.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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)

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2006

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Senior Secured Term Loan Due Two Thousand And Seventeen [Member]

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_Term_Loans_Narrative_Deta

Debt - Term Loans Narrative (Details) (USD $)	3 Months Ended	9 Months Ended
	Dec. 31, 2012	Sep. 30, 2013	Nov. 07, 2012
Long-Term Debt Instrument [Line Items]	'	'	'
Credit Facility Commitment Period	'five-year	'	'
Unsecured Debt	'	'	$2,000,000,000
Net proceeds from issuance of unsecured loan	1,935,000,000	'	'
Debt Instrument Margin Rate Range, Minimum	'	4.50%	'
Base Rate Margin	'	0.50%	'
Euro Rate Margin	'	1.00%	'
Long-term Debt, Gross	12,620,000,000	12,736,000,000	'
Term Loan [Member]	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'
Debt Instrument Margin Rate Range, Minimum	'	3.50%	'
Term Loan [Member] | Euro Rate Floor Percentage Per Annum [Member]	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	1.25%	'
Term Loan [Member] | Base Rate Floor Percentage Per Annum [Member]	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'
Debt Instrument, Interest Rate, Stated Percentage	'	2.25%	'
Term Loan [Member] | Maximum	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'
Long-term Debt, Gross	'	$125,000,000	'

Debt_Senior_Notes_and_Continge

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

9 Months Ended

9 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Nov. 07, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

7.625% Senior Notes Due 2013

6.625% Senior Notes Due 2019

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

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

6.775% Senior Notes Due 2019

7.625% Senior Notes Due 2013

7.625% Senior Notes Due 2013

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

Long-Term Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Outstanding Principal Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$50,000,000

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

7.63%

6.63%

'

2.50%

'

2.75%

'

2.25%

'

3.25%

'

6.78%

'

'

7.63%

'

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

2,274,000,000

1,263,000,000

'

'

'

'

2,274,000,000

'

'

'

'

'

'

'

'

'

1,263,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Long-term Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Unsecured Debt

'

'

'

2,000,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument Principal Amount Redeemed Percent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

35.00%

'

'

'

'

'

'

'

'

Long-term Debt, Gross

12,736,000,000

'

12,620,000,000

'

'

'

'

1,168,000,000

1,168,000,000

396,000,000

396,000,000

347,000,000

347,000,000

500,000,000

0

0

'

1,300,000,000

0

464,000,000

650,000,000

650,000,000

700,000,000

0

1,100,000,000

0

97,000,000

474,000,000

'

Debt Instrument, Face Amount

'

'

'

'

'

'

2,300,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Write off of Deferred Debt Issuance Cost

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

19,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Write-off of Debt Discount

'

'

'

'

'

'

32,000,000

'

'

'

'

'

'

'

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Notes Payable

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

247,000,000

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchase Amount

'

'

'

'

'

'

405,000,000

'

'

'

'

'

'

'

'

'

'

'

221,000,000

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchased Face Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

217,000,000

'

'

'

'

'

'

'

377,000,000

'

'

Gain (Loss) on Repurchase of Debt Instrument

'

'

'

'

'

'

$37,000,000

'

'

'

'

'

'

'

'

$33,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt_Senior_Notes_and_Continge1

Debt - Senior Notes and Contingent Convertible Senior Notes Purchased ( Table Phantom) (Details)	Sep. 30, 2013
7.625% Senior Notes Due 2013	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	7.63%
6.625% Senior Notes Due 2019	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Term Loan [Member] | Senior Secured Term Loan Due Two Thousand And Seventeen [Member]	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument Maturity Year	'2017
Senior Notes | 7.625% Senior Notes Due 2013	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	7.63%
Debt Instrument Maturity Year	'2013
Senior Notes | 9.5% Senior Notes Due 2015	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	9.50%
Debt Instrument Maturity Year	'2015
Senior Notes | 3.25% Senior Notes due 2016	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Debt Instrument Maturity Year	'2016
Senior Notes | 6.5% Senior Notes Due 2017	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.50%
Debt Instrument Maturity Year	'2017
Senior Notes | 6.875% Senior Notes Due 2018	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument Maturity Year	'2018
Senior Notes | 7.25% Senior Notes Due 2018	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	7.25%
Debt Instrument Maturity Year	'2018
Senior Notes | 6.625% Senior Notes Due 2019	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Year	'2019
Senior Notes | 6.775% Senior Notes Due 2019	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.78%
Debt Instrument Maturity Year	'2019
Senior Notes | 6.625% Senior Notes Due 2020	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.63%
Debt Instrument Maturity Year	'2020
Senior Notes | 6.875% Senior Notes Due 2020	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.88%
Debt Instrument Maturity Year	'2020
Senior Notes | 5.375% Senior Notes due 2021 [Member]	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.38%
Debt Instrument Maturity Year	'2021
Senior Notes | 6.125% Senior Notes Due 2021	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	6.13%
Debt Instrument Maturity Year	'2021
Senior Notes | 5.75% Senior Notes due 2023 [Member]	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	5.75%
Debt Instrument Maturity Year	'2023
Senior Notes | 2.75% Contingent Convertible Senior Notes Due 2035	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.75%
Debt Instrument Maturity Year	'2035
Senior Notes | 2.5% Contingent Convertible Senior Notes due 2037	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.50%
Debt Instrument Maturity Year	'2037
Senior Notes | 2.25% Contingent Convertible Senior Notes Due 2038	'
Long-Term Debt Instrument [Line Items]	'
Debt Instrument, Interest Rate, Stated Percentage	2.25%
Debt Instrument Maturity Year	'2038

Debt_Bank_Credit_Facilities_Ta

Debt Bank Credit Facilities Table (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Line of Credit Facility [Line Items]	'
Facility structure	'Senior secured revolving
Maturity date	'November 2016
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 September 30, 2013	0
Letters of credit outstanding as of September 30, 2013	23
Oilfield Services Revolving Bank Credit Facility	'
Line of Credit Facility [Line Items]	'
Borrowing capacity	500
Amount outstanding as of September 30, 2013	285
Letters of credit outstanding as of September 30, 2013	0

Debt_Narrative_Details

Debt - Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2013	Sep. 30, 2012
Long-Term Debt Instrument [Line Items]	'	'	'	'
Number of revolving bank credit facilities used	'	'	2	'
Debt Instrument Margin Rate Range, Minimum	'	'	4.50%	'
Long-term Debt, Gross	'	12,620,000,000	$12,736,000,000	'
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%	'
Debt Instrument, Covenant Description	'4.75 to 1.00	'5.00 to 1.00	'4.00 to 1.00	'6.00 to 1.00
Increase to Applicable Margin, Credit Facility	'	'	0.25%	'
Credit Facility Borrowing Capacity Margin	'	'	50.00%	'
Minimum Collateral Value, Credit Facility	'	'	75,000,000	'
Line of Credit Facility, Amount Outstanding	'	'	0	'
Corporate Revolving Bank Credit Facility | Maximum	'	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'	'
Debt Instrument, Convertible, Effective Interest Rate	'	'	2.25%	'
Long-term Debt	'	'	125,000,000	'
Corporate Revolving Bank Credit Facility | Minimum	'	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'	'
Debt Instrument Margin Rate Range, Minimum	'	'	1.50%	'
Debt Outstanding Principal Amount	'	'	50,000,000	'
Corporate Revolving Bank Credit Facility | Union Bank N.A. | Maximum	'	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'	'
Debt Instrument, Convertible, Effective Interest Rate	'	'	1.25%	'
Corporate Revolving Bank Credit Facility | Union Bank N.A. | Minimum	'	'	'	'
Long-Term Debt Instrument [Line Items]	'	'	'	'
Debt Instrument Margin Rate Range, Minimum	'	'	0.50%	'
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	'
Line of Credit Facility, Amount Outstanding	'	'	285,000,000	'
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 Margin Rate Range, Minimum	'	'	1.00%	'
Debt Instrument, Convertible, Effective Interest Rate	'	'	1.75%	'
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%	'
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%	'

Contingencies_and_Commitments_2

Contingencies and Commitments - Contingencies Narrative (Details) (USD $)	Sep. 30, 2013
Loss Contingencies [Line Items]	'
Loss Contingency, Range of Possible Loss, Minimum	$100,000

Contingencies_and_Commitments_3

Contingencies and Commitments - Aggregate Undiscounted Commitments on Gathering Processing and Transportation Agreements Table (Details) (USD $)	Sep. 30, 2013
In Millions, unless otherwise specified
Contractual Obligation, Fiscal Year Maturity [Abstract]	'
Service Agreement Commitment 2013	$510
Service Agreement Commitment 2014	2,010
Service Agreement Commitment 2015	1,821
Service Agreement Commitment 2016	1,910
Service Agreement Commitment 2017	1,942
Service Agreement Commitment 2018 - 2099	9,546
Service Commitment Agreement Total	$17,739

Contingencies_and_Commitments_4

Contingencies and Commitments - Commitments Narrative (Details) (USD $)

1 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Apr. 30, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2013

Jul. 31, 2011

Dec. 31, 2011

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Fair Value Amount Remianing [Member]

Scenario, Forecast [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

Sundrop Fuels, Inc.

Sundrop Fuels, Inc.

Chesapeake Midstream Development, L.P

Chesapeake Midstream Development, L.P

Chesapeake Midstream Development, L.P

Chesapeake Midstream Development, L.P

Minimum

Maximum

Net Acreage Shortfall [Member]

Net Acreage Shortfall [Member]

Rigs

Rigs

Rigs

Rigs

Equipment

Equipment

Equipment

Compressor Leases

Compressor Leases

Compressor Leases

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Gas Gathering and Processing Equipment [Member]

Assets Held-for-sale [Member]

well

well

Year of 2012 [Member]

Year of 2013 [Member]

Chesapeake Utica L L C [Member]

Chesapeake Utica L L C [Member]

acre

Scenario, Forecast [Member]

Subsequent Event [Member]

Scenario, Forecast [Member]

Minimum

Rigs

Minimum

Maximum

Compressor

Minimum

Maximum

Gas Gathering and Processing Equipment [Member]

acre

Subsequent Event [Member]

Scenario, Forecast [Member]

Subsequent Event [Member]

Long-term Purchase Commitment [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equipment sold

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

94

'

'

'

'

'

'

2,558

'

'

'

'

'

'

'

Master Lease Agreement Miinimum Term (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'5 years

'

'

'

'

'

'

'

'4 years

'

'

'

'

'

'

Master Lease Agreement Maximum Term (in years)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

Number of repurchased equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

28

9

'

'

'

'

'

250

'

'

'

'

'

'

'

Property Subject to or Available for Operating Lease, Number of Units

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11

'

'

'

'

'

'

'

'

'

'

Lease Term

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'1 year

'3 years

'

'

'

'

'

'

'

'

Operating Leases, Future Minimum Payments Due

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$239

'

'

$58

$82

'

'

$348

'

'

'

'

'

'

'

Payments to Acquire Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

70

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Sale of Property, Plant, and Equipment

'

'

'

'

'

'

'

'

'

'

'

884

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

357

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Drilling carrying percentage, previous amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

60.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Drilling carrying percentage, current amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other Commitment

'

50

'

50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment of Long-Lived Assets to be Disposed of

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

26

Net Acreage Shortfall

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

13,000

14,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Payment for Shortfall

'

'

'

'

'

'

28

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Payable On Each Short Of Drilling Commitment

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Guaranteed gross profit margin

10.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Investment in preferred stock

'

'

'

'

'

'

'

'

'

115

155

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

EBITDA minimum commitment amount

'

'

'

'

'

'

'

'

'

'

'

'

'

100

150

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on Sale of Property Plant Equipment

'

132

-7

290

-5

8

'

'

'

'

'

27

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

132

7

311

8

'

Income (Loss) from Continuing Operations before Income Taxes, Extraordinary Items, Noncontrolling Interest

'

'

'

'

'

'

'

'

'

'

'

'

$11

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Other_Liabilities_ShortTerm_Ta

Other Liabilities, Short-Term Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Other Liabilities, Current [Abstract]	'	'
Revenues and royalties due others	$1,621	$1,337
Accrued natural gas, oil and NGL drilling and production costs	417	525
Joint interest prepayments received	472	749
Accrued compensation and benefits	276	225
Accrued Liabilities for Commissions, Expense and Taxes	178	130
Accrued dividends	102	101
Other	559	674
Total other current liabilities	$3,625	$3,741

Other_Liabilities_LongTerm_Tab

Other Liabilities, Long-Term Table (Details) (USD $)	9 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2011	Dec. 31, 2009	Dec. 31, 2012
	Property	Property	Property
Other Long-Term Liabilities [Line Items]	'	'	'	'
Financing obligations(c)	$191	'	'	$175
Mortgages payable(d)	0	'	'	56
Other	580	'	'	506
Total other long-term liabilities	1,180	'	'	1,176
Other liabilities, current	3,625	'	'	3,741
Number Of Real Estate Assets Financed	'	'	111	'
Operating Leases, Income Statement, Minimum Lease Revenue	'	'	145	'
Lease Agreement Contractual Term	'	'	'40 years	'
Capital Leases, Future Minimum Payments Receivable	'	'	54	'
Number Of Real Estate Surface Assets Repurchased	4	1	'	'
Mortgage Term	'	'	'5 years	'
Debt Instrument, Basis Points	'	'	275	'
Minimum	'	'	'	'
Other Long-Term Liabilities [Line Items]	'	'	'	'
Capital Leases, Future Minimum Payments Receivable	'	'	15	'
Maximum	'	'	'	'
Other Long-Term Liabilities [Line Items]	'	'	'	'
Capital Leases, Future Minimum Payments Receivable	'	'	27	'
Chesapeake Utica L L C [Member]	'	'	'	'
Other Long-Term Liabilities [Line Items]	'	'	'	'
Conveyance Obligation Noncurrent	256	'	'	275
Total other long-term liabilities	279	'	'	293
Other liabilities, current	23	'	'	18
Chesapeake Cleveland Tonkawa L.L.C	'	'	'	'
Other Long-Term Liabilities [Line Items]	'	'	'	'
Conveyance Obligation Noncurrent	153	'	'	164
Total other long-term liabilities	163	'	'	178
Other liabilities, current	$10	'	'	$14

Stockholders_Equity_Common_Sto

Stockholders' Equity, Common Stock Table (Details)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011	Sep. 29, 2013	Sep. 29, 2012	Sep. 29, 2013	Sep. 29, 2012
					Restricted stock	Restricted stock	Stock Options	Stock Options
Increase (Decrease) in Stockholders' Equity [Roll Forward]	'	'	'	'	'	'	'	'
Common Stock, Shares, Issued Beginning of Period	667,472,869	666,467,664	666,955,284	660,888,159	'	'	'	'
Restricted stock issuances (net of forfeitures)(a)	'	'	'	'	684,000	5,758,000	'	'
Stock option exercises	'	'	'	'	'	'	321,000	309,000
Common Stock, Shares, Issued End of Period	667,472,869	666,467,664	666,955,284	660,888,159	'	'	'	'

Stockholders_Equity_Convertibl

Stockholders' Equity, Convertible Preferred Stock Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding as of January 1, 2013 and 2012 and September 30, 2013 and 2012 (in thousands)	7,251,515	7,251,515	7,251,515	7,251,515
5.75% Cumulative Convertible Preferred Stock	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding as of January 1, 2013 and 2012 and September 30, 2013 and 2012 (in thousands)	1,497,000	1,497,000	1,497,000	1,497,000
Liquidation preference per share	1,000	'	'	'
5.75% Cumulative Convertible Preferred Stock Series A	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding as of January 1, 2013 and 2012 and September 30, 2013 and 2012 (in thousands)	1,100,000	1,100,000	1,100,000	1,100,000
Liquidation preference per share	1,000	'	'	'
4.50% Cumulative Comvertible Preferred Stock [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Shares outstanding as of January 1, 2013 and 2012 and September 30, 2013 and 2012 (in thousands)	2,559,000	2,559,000	2,559,000	2,559,000
Liquidation preference per share	100	'	'	'
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, 2013 and 2012 and September 30, 2013 and 2012 (in thousands)	2,096,000	2,096,000	2,096,000	2,096,000
Liquidation preference per share	100	'	'	'

Stockholders_Equity_StockBased2

Stockholders' Equity, Stock-Based Compensation Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Natural gas and oil properties	$12	$18	$45	$55
General and administrative expenses	13	17	48	55
Natural gas, oil and NGL production expenses	5	6	17	18
Marketing, gathering and compression expenses	2	4	5	12
Oilfield services expenses	3	2	8	8
Total	$35	$47	$123	$148

Stockholders_Equity_Restricted

Stockholders' Equity, Restricted Stock Restricted Stock Table (Details) (USD $)	9 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Sep. 29, 2013	Sep. 30, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]	'	'	'
Unvested shares as of January 1, 2013	'	$21.85	$23.72
Granted	$19.44	'	'
Vested	$23.31	'	'
Forfeited	$21.61	'	'
Unvested shares as of September 30, 2013	'	$21.85	$23.72
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]	'	'	'
Unvested shares as of January 1 (shares)	'	17,046	18,899
Granted (shares)	9,053	'	'
Vested (shares)	-9,553	'	'
Forfeited (usd per share)	-1,353	'	'
Unvested shares as of March 31 (shares)	'	17,046	18,899

Stockholders_Equity_Stock_Opti

Stockholders' Equity, Stock Option Activity Table (Details) (USD $)	0 Months Ended		9 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Sep. 29, 2013	Dec. 30, 2012	Sep. 29, 2013	Sep. 30, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'	'	'	'
Outstanding at January 1, 2013	'	'	'	5,306	481
Granted	'	'	5,264	'	'
Exercised	'	'	-345	'	'
Expired	'	'	-94	'	'
Outstanding at September 30, 2013	'	'	'	5,306	481
Exercisable at September 30, 2013	'	'	'	1,386	'
Weighted Average Exercise Price [Roll Forward]	'	'	'	'	'
Stock Options, Weighted Average Exercise Price (usd per share), Beginning of Period	'	'	'	$19.27	$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	'	'	$10.81	'	'
Share-based Compensation Arrangements by Share-based Payment Award, Options, Expirations in Period, Weighted Average Exercise Price	'	'	$19.43	'	'
Stock Options, Weighted Average Exercise Price (usd per share), End of Period	'	'	'	$19.27	$12.69
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Exercise Price	'	'	'	$18.79	'
Weighted Average Contract Life (in years) [Roll Forward]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Weighted Average Remaining Contractual Term	'7 years 2 months 5 days	'11 months 15 days	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	'2 years 4 months 1 day	'	'	'	'
Aggregate Intrinsic Value [Roll Forward]	'	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	'	'	'	$35	$2
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	'	'	'	$10	'

Stockholders_Equity_Performanc

Stockholders' Equity, Performance Shares Table (Details) (USD $)

3 Months Ended

9 Months Ended

In Millions, except Share data, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Mar. 31, 2012

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]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Year of 2013 [Member]

Year of 2013 [Member]

Performance Shares [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Payable 2013 [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Payable 2014 [Member]

Payable 2014 [Member]

Payable 2015 [Member]

Payable 2015 [Member]

Payable 2016 [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

'

'

'

'

'

1,112,330

'

278,084

'

834,246

'

1,637,601

'

Fair Value of Share Based Award

'

'

'

'

'

$39

$31

$10

$8

$29

$23

$54

$37

Share Based Award Liability, Current

'

'

'

'

'

38

'

10

'

28

'

40

'

Allocated Share-based Compensation Expense

$35

$47

$123

$148

$2

'

'

'

'

'

'

'

'

Stockholders_Equity_StockBased3

Stockholders' Equity, Stock-Based Compensation and Performance Share Units Narrative (Details) (USD $)

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Dec. 31, 2005

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

In Millions, unless otherwise specified

4.50% Cumulative Comvertible Preferred Stock [Member]

5.75% Cumulative Convertible Preferred Stock

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

Restricted Stock

Restricted Stock

Restricted Stock

Restricted Stock

Restricted Stock

RSA [Member]

RSA [Member]

RSU [Member]

Stock Options

Stock Options

Stock Options

Stock Options

Stock Options

Stock Options

Stock Options

Incentive Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Retention Based Stock Option Award [Member]

Performance Shares [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]

Minimum

Maximum

Director [Member]

Management [Member]

Prior to 2006 [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

Performance Shares [Member]

TSR [Member]

TSR [Member]

Operational Component [Member]

Operational Component [Member]

Employee [Member]

Employee [Member]

Management [Member]

Stock Option Award Three Year Anniversary [Member]

Stock Option Award Four Year Anniversary [Member]

Stock Option Award Five Year Anniversary [Member]

Year of 2012 [Member]

Year of 2012 [Member]

Minimum

Maximum

Maximum

Minimum

Maximum

Minimum

Maximum

TSR is less than zero [Member]

Management [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]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

Management [Member]

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

4.50%

5.75%

5.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'3 years

'4 years

'3 years

'

'

'

'

'

'

'4 years

'3 years

'

'3 years

'4 years

'5 years

'3 years

'

'

'

'

'

'

'

'

'

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

'

'

'

'

$187

'

$187

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

244

'

244

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'2 years 7 months

'

'

'

'

'

'

'

'2 years 10 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Recognized reductions in tax benefits

'

'

'

'

0

14

12

19

'

'

'

'

2

0

2

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

33.00%

'

'

'

'

100.00%

250.00%

0.00%

125.00%

200.00%

0.00%

125.00%

0.00%

62.50%

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'10 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

$19

'

$19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Stockholders_Equity_Noncontrol

Stockholders Equity, Noncontrolling Interests (Details) (USD $)

3 Months Ended

9 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

1 Months Ended

2 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Mar. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Mar. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Mar. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Nov. 30, 2011

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Oct. 31, 2011

Dec. 31, 2011

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Nov. 30, 2011

Wireless Seismic, Inc. [Member]

Wireless Seismic, Inc. [Member]

Wireless Seismic, Inc. [Member]

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake 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 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]

5.75% Cumulative Convertible Preferred Stock

Subordinated Units

Preferred Stock

Preferred Stock

Common Unit

Common Unit

acre

well

well

well

well

Minimum

Maximum

Drilled Wells

Future [Member]

Future [Member]

Increase

well

acre

Minimum

Maximum

Initial Wells [Member]

acre

well

acre

well

well

Minimum

Drilled Wells

Drilled Wells

Chesapeake Granite Wash Trust

Chesapeake Cleveland Tonkawa L.L.C

Chesapeake Utica L L C [Member]

Chesapeake Granite Wash Trust

Chesapeake Granite Wash Trust

acre

acre

well

well

Minimum

well

well

Minimum

well

well

well

acre

well

well

well

well

Noncontrolling Interest [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

5.75%

'

'

'

'

'

Acres of leasehold land

'

'

'

'

'

'

'

'

'

245,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Third-Party investors' contributions

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$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%

'

'

3.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Productive Oil Wells, Number of Wells, Net

'

'

'

'

'

'

'

'

'

'

73

58

73

58

'

'

'

'

'

1,000

1,000

'

'

'

'

'

'

'

'

'

'

'

1,500

1,500

'

1,500

'

'

1,300

'

'

'

'

'

'

'

'

Restricted cash and cash equivalents, current

75,000,000

'

75,000,000

'

111,000,000

'

'

'

'

'

38,000,000

'

38,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

37,000,000

'

37,000,000

'

'

'

'

'

'

'

'

'

'

'

Restricted Cash and Cash Equivalents, Noncurrent

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

155,000,000

'

'

'

'

'

'

'

'

'

Acre Spacing

'

'

'

'

'

'

'

'

'

'

160

'

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)

'

'

'

'

'

'

'

'

'

'

$1,260

'

$1,260

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,270

'

$1,270

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

80

50

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100

31

'

'

'

'

'

'

'

'

'

'

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

'

150

'

'

'

'

'

'

'

'

'

'

'

Number of development wells drilled

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

80

'

'

'

'

'

118

'

'

'

'

'

'

'

'

86

40

'

'

'

'

'

'

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

667,472,869

666,955,284

667,472,869

666,955,284

666,467,664

660,888,159

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

23,000,000

Common stock, par value (usd per share)

$0.01

'

$0.01

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of units included in beneficial interests

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,687,500

'

'

12,062,500

'

Percentage of beneficial interest owned

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

51.00%

'

'

'

'

'

'

'

'

'

'

4.00%

'

'

'

'

'

'

'

'

'

'

'

Common shares, outstanding

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

46,750,000

'

46,750,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of proceeds from royalty interest conveyed to trust

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

90.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of producing wells

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69

'

69

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of gross acres

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

45,400

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Net Acreage Shortfall

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

29,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum amount recoverable by trust under lien

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

263,000,000

'

'

'

'

85,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of incentive distributions received

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling Interest, Ownership Percentage by Parent

'

'

'

'

'

'

51.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments of Ordinary Dividends, Preferred Stock and Preference Stock

'

'

128,000,000

128,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

212,000,000

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, par value (usd per share)

$0.01

'

$0.01

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$1,115

'

$1,115

'

'

'

'

'

'

'

'

'

'

'

Percentage of Preferred Shares Repurchased

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

Premium on purchase of preferred shares of a subsidiary

0

0

69,000,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

69,000,000

'

'

'

'

'

'

'

'

'

'

'

Stock Redeemed or Called During Period, Shares

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

190,000

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling interests

2,152,000,000

'

2,152,000,000

'

2,327,000,000

'

7,000,000

'

5,000,000

'

1,015,000,000

'

1,015,000,000

'

1,015,000,000

'

'

'

'

'

'

'

323,000,000

'

323,000,000

'

356,000,000

'

'

'

'

'

'

807,000,000

'

807,000,000

'

950,000,000

'

'

'

'

'

'

'

'

'

Net Income (Loss) Attributable to Noncontrolling Interest

$38,000,000

$41,000,000

$127,000,000

$131,000,000

'

'

$1,000,000

$3,000,000

'

'

$19,000,000

$19,000,000

$56,000,000

$38,000,000

'

'

'

'

'

'

'

'

$2,000,000

$1,000,000

$14,000,000

$28,000,000

'

'

'

'

'

'

'

$18,000,000

$22,000,000

$60,000,000

$66,000,000

'

'

'

'

'

'

'

'

'

'

Stockholders_Equity_Noncontrol1

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

Derivative_and_Hedging_Activit2

Derivative and Hedging Activities Derivative Instruments Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Derivative [Line Items]	'	'
Fair Value	($583)	($924)
Natural Gas [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	661,000,000,000,000	353,000,000,000,000
Fair Value	-121	-231
Natural Gas [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	341,000,000,000,000	49,000,000,000,000
Fair Value	96	24
Natural Gas [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	193,000,000,000,000	193,000,000,000,000
Fair Value	-219	-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	79,000,000,000,000	111,000,000,000,000
Fair Value	-2	-15
Natural Gas [Member] | Three Way Collar [Member]	'	'
Derivative [Line Items]	'	'
Volume, Energy Measurement	36,000,000,000,000	0
Fair Value	4	0
Crude Oil [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	103,000,000	112,700,000
Fair Value	-462	-693
Crude Oil [Member] | Swap	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	31,600,000	28,100,000
Fair Value	-94	68
Crude Oil [Member] | Call Option	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	65,600,000	73,800,000
Fair Value	-368	-748
Crude Oil [Member] | Swaptions	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	5,300,000	5,300,000
Fair Value	-1	-13
Crude Oil [Member] | Basis Swap [Member]	'	'
Derivative [Line Items]	'	'
Volume, Volume Measurement	500,000	5,500,000
Fair Value	$1	$0

Derivative_and_Hedging_Activit3

Derivative and Hedging Activities Natural Gas and Oil Sales Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
General Discussion of Derivative Instruments and Hedging Activities [Abstract]	'	'	'	'
Natural gas, oil and NGL sales	$1,839	$1,464	$5,303	$3,798
Gains (losses) on natural gas, oil and NGL derivatives	-253	-27	141	824
Total natural gas, oil and NGL sales	$1,586	$1,437	$5,444	$4,622

Derivative_and_Hedging_Activit4

Derivative and Hedging Activities Interest Rate Derivatives Table (Details) (Swap, USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Swap	'	'
Derivative [Line Items]	'	'
Notional Amount	$2,500	$1,050
Fair Value	($88)	($35)

Derivative_and_Hedging_Activit5

Derivative and Hedging Activities Interest Income and Interest Expense Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Interest Income (Expense), Net [Abstract]	'	'	'	'
Interest expense on senior notes	$180	$187	$560	$546
Interest expense on credit facilities	8	13	30	51
Interest expense on term loans	29	112	87	173
(Gains) losses on interest rate derivatives	-3	-2	51	-4
Amortization of loan discount, issuance costs and other	21	24	70	67
Capitalized interest	-195	-298	-634	-770
Total interest expense	$40	$36	$164	$63

Derivative_and_Hedging_Activit6

Derivative and Hedging Activities Derivative Instruments in Balance Sheet Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Liability Derivatives:	'	'
Total derivative instruments	($676)	($979)
Commodity contracts	'	'
Asset Derivatives:	'	'
Asset commodity contracts	115	110
Commodity contracts | Short [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	104	52
Commodity contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	11	5
Liability Derivatives:	'	'
Liability commodity contracts	9	3
Foreign currency contracts	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Foreign currency contracts | Short [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	0	0
Foreign currency contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Liability Derivatives:	'	'
Liability commodity contracts	0	0
Interest rate contract	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Interest rate contract | Short [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	0	0
Interest rate contract | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	0	0
Liability Derivatives:	'	'
Liability commodity contracts	0	0
Designated as Hedging Instrument	'	'
Liability Derivatives:	'	'
Liability commodity contracts	-5	-20
Designated as Hedging Instrument | Foreign currency contracts	'	'
Liability Derivatives:	'	'
Liability commodity contracts	'	-20
Designated as Hedging Instrument | Foreign currency contracts | Long [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	-5	'
Not designated as hedging instruments	'	'
Asset Derivatives:	'	'
Asset commodity contracts	126	115
Liability Derivatives:	'	'
Liability commodity contracts	-797	-1,074
Not designated as hedging instruments | Commodity contracts | Short [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	115	110
Liability Derivatives:	'	'
Liability commodity contracts	-265	-157
Not designated as hedging instruments | Commodity contracts | Long [Member]	'	'
Asset Derivatives:	'	'
Asset commodity contracts	11	5
Liability Derivatives:	'	'
Liability commodity contracts	-444	-882
Not designated as hedging instruments | Interest rate contract | Short [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	-9	0
Not designated as hedging instruments | Interest rate contract | Long [Member]	'	'
Liability Derivatives:	'	'
Liability commodity contracts	($79)	($35)

Derivative_and_Hedging_Activit7

Derivative and Hedging Activities Netting Offsets Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Short-term derivative assets	$11	$58
Long-term derivative assets	2	2
Short-term derivative liabilities	-170	-105
Long-term derivative liabilities	-519	-934
Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	115	110
Derivative Asset, Fair Value, Gross Liability	-104	-52
Derivative Asset, Fair Value, Net	11	58
Short-term derivative assets	'	58
Interest rate contract	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	0	0
Foreign currency contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Net	0	0
Short [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Short-term derivative liabilities	-170	'
Short [Member] | Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Liability, Fair Value, Gross Asset	-265	-157
Liability commodity contracts	104	52
Derivative Liability, Fair Value, Net	-161	-105
Short-term derivative liabilities	'	-105
Short [Member] | Interest rate contract	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Liability, Fair Value, Gross Asset	-9	0
Liability commodity contracts	0	0
Derivative Liability, Fair Value, Net	-9	0
Short [Member] | Foreign currency contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Liability, Fair Value, Gross Asset	0	0
Liability commodity contracts	0	0
Derivative Liability, Fair Value, Net	0	0
Long [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term derivative assets	2	'
Long [Member] | Commodity contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	11	5
Derivative Asset, Fair Value, Gross Liability	-9	-3
Derivative Asset, Fair Value, Net	2	2
Derivative Liability, Fair Value, Gross Asset	-444	-882
Liability commodity contracts	9	3
Derivative Liability, Fair Value, Net	-435	-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]	'	'
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	0	0
Derivative Liability, Fair Value, Gross Asset	-79	-35
Liability commodity contracts	0	0
Derivative Liability, Fair Value, Net	-79	-35
Long [Member] | Foreign currency contracts	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Derivative Asset, Fair Value, Gross Asset	0	0
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	0	0
Derivative Liability, Fair Value, Gross Asset	-5	-20
Liability commodity contracts	0	0
Derivative Liability, Fair Value, Net	($5)	($20)

Derivative_and_Hedging_Activit8

Derivative and Hedging Activities Derivative Instruments, Gain/Loss In Statement Of Financial Performance Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Interest rate contracts	$3	$2	($51)	$4
Fair Value Hedging | Interest rate contract | Interest Expense	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Interest rate contracts	$1	$2	$4	$6

Derivative_and_Hedging_Activit9

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

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Sep. 29, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2011

Sep. 29, 2013

Sep. 29, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Dec. 31, 2011

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 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]

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 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

Balance After Tax

Balance After Tax

Balance After Tax

Cash Flow Hedges [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

AOCI (Loss), Net of Tax - Period Start

($169)

($182)

'

'

($182)

'

($174)

($189)

'

'

'

'

($280)

($286)

($304)

($311)

($306)

($287)

'

'

'

'

($174)

($178)

($189)

($193)

($190)

($178)

Other Comprehensive Income Before Reclassifications, Net of Tax

'

'

'

'

'

'

'

'

3

4

3

4

'

'

'

'

'

'

2

3

2

3

'

'

'

'

'

'

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

'

'

0

17

17

13

'

'

3

-9

21

-28

'

'

'

'

'

'

2

-6

13

-18

'

'

'

'

'

'

AOCI (Loss), Net of Tax - Period End

($169)

($182)

'

'

'

'

($174)

($189)

'

'

'

'

($280)

($286)

($304)

($311)

($306)

($287)

'

'

'

'

($174)

($178)

($189)

($193)

($190)

($178)

Recovered_Sheet2

Derivative and Hedging Activities Cash Flow Hedge Instruments Gain Loss in Statement of Financial Performance Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (Loss) on Cash Flow Hedge Effectiveness Total	$3	$4	$3	$4
Natural Gas, Oil and NGL sales	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (Loss) on Cash Flow Hedge Effectiveness Total	-3	9	-21	28
Commodity contracts | Natural Gas, Oil and NGL sales	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	-3	9	-21	28
Foreign currency contracts | Accumulated Other Comprehensive Income (Loss) [Member]	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (Loss) Reclassified from AOCI Effective Portion):	$3	$4	$3	$4

Recovered_Sheet3

Derivative and Hedging Activities Derivatives Not Designated as Hedging Instruments Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (loss) recognized in net income (loss)	$3	$2	($51)	$4
Not designated as hedging instruments	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (loss) recognized in net income (loss)	-248	-36	107	794
Not designated as hedging instruments | Commodity contracts | Natural Gas, Oil and NGL sales	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (loss) recognized in net income (loss)	-250	-36	162	796
Not designated as hedging instruments | Interest rate contract | Interest Expense	'	'	'	'
Derivative Instruments, Gain (Loss) [Line Items]	'	'	'	'
Gain (loss) recognized in net income (loss)	$2	$0	($55)	($2)

Recovered_Sheet4

Derivative and Hedging Activities Narrative (Details)

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Jun. 30, 2011

Sep. 30, 2013

Dec. 31, 2006

Dec. 31, 2006

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

USD ($)

USD ($)

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Multi-Counterparty Hedging Facility

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]

USD ($)

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

6.25% Euro-Denominated Senior Notes Due 2017

USD ($)

Credit Risk

Energy Related Derivative [Member]

Price Risk Derivative [Member]

Semi-Annual Collateral Dates

Between Semi-Annual Collateral Dates

Multi-Counterparty Hedging Facility

Multi-Counterparty Hedging Facility

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]

counterparty

counterparty

Mcfe

Mcfe

Mcfe

Mcfe

EUR (€)

USD ($)

USD ($)

EUR (€)

Maturity Payment [Member]

Maturity Payment [Member]

USD ($)

EUR (€)

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of counterparties in hedge facility

'

'

'

'

'

'

'

'

'

'

'

16

15

'

'

'

'

'

'

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

'

'

'

'

'

'

'

'

'

'

'

'

'

6,400,000,000

6,400,000,000

'

'

'

'

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)

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,200,000,000

100,000,000

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

'

'

2,300,000,000

'

'

'

'

'

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

'

'

'

'

'

'

1.3527

1.3325

'

'

'

'

'

'

'

'

'

'

'

Liability commodity contracts

'

'

'

'

'

'

5,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Euro-denominated debt in notes payable, adjusted value

12,736,000,000

12,620,000,000

'

465,000,000

454,000,000

'

465,000,000

'

'

'

'

'

'

'

'

'

'

'

'

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

166,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Flow Hedges, Accumulated OCI Balance

174,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected amount to be transferred of during the next 12 months

$22,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Derivative, Number of Instruments Held

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Divestitures_Joint_Ventures_Ta

Divestitures Joint Ventures Table (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Jun. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2011

Sep. 30, 2013

Feb. 28, 2011

Sep. 30, 2013

Nov. 30, 2010

Sep. 30, 2013

Jan. 31, 2010

Sep. 30, 2013

Nov. 30, 2008

Sep. 30, 2013

Sep. 30, 2008

Sep. 30, 2013

Jul. 31, 2008

Sep. 30, 2013

Sep. 30, 2013

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

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

Corporate Joint Venture [Member]

Payment at Closing [Member]

Payment Remaining [Member]

Payment Remaining [Member]

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

$1,020

'

$949

$71

$71

$610

'

$570

'

$1,120

'

$800

'

$1,250

'

$1,100

'

$1,650

'

$8,049

Total Drilling Carries

0

'

'

'

'

1,422

'

697

'

1,080

'

1,403

'

2,125

'

800

'

1,508

'

9,035

Total Cash And Drilling Carry Proceeds

949

'

'

'

'

2,032

'

1,267

'

2,200

'

2,203

'

3,375

'

1,900

'

3,158

'

17,084

Drilling Carries Remaining

'

$0

'

'

'

'

$714

'

$233

'

$0

'

$0

'

$0

'

$0

'

$0

$947

Percentage of Total Payment by Joint Venture Partner

'

'

93.00%

'

7.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage Reimbursed

'

'

'

'

'

'

60.00%

'

67.00%

'

'

'

'

'

'

'

'

'

'

'

Divestitures_VPP_Transactions_

Divestitures VPP Transactions Table (Details) (USD $)

9 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Dec. 31, 2007

Jun. 30, 2008

31-May-08

31-May-08

31-May-08

31-May-08

Sep. 30, 2008

Aug. 31, 2008

Aug. 31, 2008

Aug. 31, 2008

Aug. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Dec. 31, 2008

Sep. 30, 2009

Aug. 31, 2009

Aug. 31, 2009

Aug. 31, 2009

Aug. 31, 2009

Mar. 31, 2010

Feb. 28, 2010

Feb. 28, 2010

Feb. 28, 2010

Feb. 28, 2010

Sep. 30, 2010

Sep. 30, 2010

Sep. 30, 2010

Sep. 30, 2010

Sep. 30, 2010

Jun. 30, 2011

31-May-11

31-May-11

31-May-11

31-May-11

Mar. 31, 2012

Mar. 31, 2012

Mar. 31, 2012

Mar. 31, 2012

Mar. 31, 2012

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

JV Mississippi Lime

JV Mississippi Lime

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 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 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 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 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 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 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 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 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

VPP 10 Aradarko Basin Granite Wash [Member]

Mcfe

Total [Member]

Total [Member]

Total [Member]

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

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Total [Member]

Natural Gas [Member]

Oil [Member]

NGL Reserves

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Mcfe

Mcf

MBbls

MBbls

Business Combination, Separately Recognized Transactions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Interest in Joint Venture

'

'

'

'

$1,020

$90

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cash Proceeds from Volumetric Production Payment (VPP)

$6,031

'

'

'

'

'

$1,100

'

'

'

'

$622

'

'

'

'

$600

'

'

'

'

$412

'

'

'

'

$370

'

'

'

'

$180

'

'

'

'

$1,150

'

'

'

'

$853

'

'

'

'

$744

'

'

'

'

Proved Developed Reserves (Volume)

'

1,216,000,000,000

5,700,000

14,000,000

'

'

'

'

208,000,000,000

0

0

'

'

94,000,000,000

0

0

'

'

93,000,000,000

0

0

'

'

95,000,000,000

500,000

0

'

'

67,000,000,000

200,000

0

'

'

44,000,000,000

300,000

0

'

'

390,000,000,000

0

0

'

'

138,000,000,000

1,700,000

4,800,000

'

'

87,000,000,000

3,000,000

9,200,000

Proved Developed Reserves (Energy)

1,334,000,000,000

'

'

'

'

'

'

208,000,000,000

'

'

'

'

94,000,000,000

'

'

'

'

93,000,000,000

'

'

'

'

98,000,000,000

'

'

'

'

68,000,000,000

'

'

'

'

46,000,000,000

'

'

'

'

390,000,000,000

'

'

'

'

177,000,000,000

'

'

'

'

160,000,000,000

'

'

'

Divestitures_VPP_Volumes_Produ

Divestitures VPP Volumes Produced During Period Table (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
	Mcfe	Mcfe	Mcfe	Mcfe
Corporate VPP [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	42,300,000,000	51,100,000,000	131,100,000,000	154,700,000,000
Corporate VPP [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	38,000,000,000	44,600,000,000	117,600,000,000	136,100,000,000
Corporate VPP [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	209,900	442,500	668,200	1,316,200
Corporate VPP [Member] | NGL Reserves	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	512,200	661,700	1,591,600	1,777,200
VPP 10 Anadarko Basin Granite Wash [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	6,700,000,000	9,500,000,000	20,900,000,000	24,500,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	3,700,000,000	5,300,000,000	11,400,000,000	13,500,000,000
VPP 10 Anadarko Basin Granite Wash [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	131,000	206,000	426,000	547,000
VPP 10 Anadarko Basin Granite Wash [Member] | NGL Reserves	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	371,900	503,700	1,158,600	1,286,600
VPP 9 Mid-Continent [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	5,200,000,000	5,800,000,000	16,000,000,000	18,100,000,000
VPP 9 Mid-Continent [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	4,100,000,000	4,500,000,000	12,500,000,000	14,000,000,000
VPP 9 Mid-Continent [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	52,300	60,800	162,500	191,000
VPP 9 Mid-Continent [Member] | NGL Reserves	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	140,300	158,000	433,000	490,600
VPP 8 Barnett Shale [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	16,600,000,000	19,400,000,000	51,600,000,000	61,100,000,000
VPP 8 Barnett Shale [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	16,600,000,000	19,400,000,000	51,600,000,000	61,100,000,000
VPP 8 Barnett Shale [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0	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	0
VPP 7 Permian Basin [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	'	1,000,000,000	'	3,400,000,000
VPP 7 Permian Basin [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	'	200,000,000	'	400,000,000
VPP 7 Permian Basin [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	'	147,300	'	490,300
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)	1,200,000,000	1,400,000,000	3,700,000,000	4,200,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,200,000,000	1,300,000,000	3,600,000,000	4,100,000,000
VPP 6 East Texas and Texas Gulf Coast [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	6,000	6,000	18,000	18,000
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	0
VPP 5 South Texas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	1,900,000,000	2,200,000,000	5,800,000,000	6,900,000,000
VPP 5 South Texas [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	1,900,000,000	2,200,000,000	5,700,000,000	6,800,000,000
VPP 5 South Texas [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	6,700	6,600	19,000	21,200
VPP 5 South Texas [Member] | NGL Reserves	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	0	0
VPP 4 Anadarko and Arkoma Basins [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	2,600,000,000	3,000,000,000	8,100,000,000	9,300,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,400,000,000	2,900,000,000	7,800,000,000	9,000,000,000
VPP 4 Anadarko and Arkoma Basins [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	13,900	15,800	42,700	48,700
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	0
VPP 3 Anadarko Basin [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	2,000,000,000	2,300,000,000	6,200,000,000	7,100,000,000
VPP 3 Anadarko Basin [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,000,000,000	2,300,000,000	6,200,000,000	7,100,000,000
VPP 3 Anadarko Basin [Member] | Oil [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	0	0	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	0
VPP 2 Texas, Oklahoma and Kansas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	2,600,000,000	2,800,000,000	7,900,000,000	8,600,000,000
VPP 2 Texas, Oklahoma and Kansas [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	2,600,000,000	2,800,000,000	7,900,000,000	8,600,000,000
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	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	0
VPP 1 Kentucky and West Virginia [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Reserves (Energy) (Duration)	3,500,000,000	3,700,000,000	10,900,000,000	11,500,000,000
VPP 1 Kentucky and West Virginia [Member] | Natural Gas [Member]	'	'	'	'
Acquisitions, Divestitures, Joint Ventures, VPP's [Line Items]	'	'	'	'
Proved Developed and Undeveloped Reserves (Volume)	3,500,000,000	3,700,000,000	10,900,000,000	11,500,000,000
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	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	0

Divestitures_VPP_Volume_Remain

Divestitures VPP Volume Remaining to Be Delivered Table (Details)

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

31-May-11

Sep. 30, 2013

31-May-11

Sep. 30, 2013

31-May-11

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2010

Sep. 30, 2013

Sep. 30, 2010

Sep. 30, 2013

Sep. 30, 2010

Sep. 30, 2013

Sep. 30, 2013

Feb. 28, 2010

Sep. 30, 2013

Feb. 28, 2010

Sep. 30, 2013

Feb. 28, 2010

Sep. 30, 2013

Sep. 30, 2013

Aug. 31, 2009

Sep. 30, 2013

Aug. 31, 2009

Sep. 30, 2013

Aug. 31, 2009

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2008

Sep. 30, 2013

Dec. 31, 2008

Sep. 30, 2013

Dec. 31, 2008

Sep. 30, 2013

Sep. 30, 2013

Aug. 31, 2008

Sep. 30, 2013

Aug. 31, 2008

Sep. 30, 2013

Aug. 31, 2008

Sep. 30, 2013

Sep. 30, 2013

31-May-08

Sep. 30, 2013

31-May-08

Sep. 30, 2013

31-May-08

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2007

Sep. 30, 2013

Dec. 31, 2007

Sep. 30, 2013

Dec. 31, 2007

Sep. 30, 2013

Corporate VPP [Member]

Corporate VPP [Member]

Corporate VPP [Member]

Corporate VPP [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 10 Anadarko Basin Granite Wash [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 9 Mid-Continent [Member]

VPP 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 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 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 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]

Reserve Volume Remaining

Natural Gas [Member]

Oil [Member]

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Oil [Member]

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Reserve Volume Remaining

Natural Gas [Member]

Natural Gas [Member]

Oil [Member]

Oil [Member]

NGL Reserves

NGL Reserves

Mcfe

Reserve Volume Remaining

Reserve Volume Remaining

Reserve Volume Remaining

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

Mcf

MBbls

MBbls

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Contract Term

'

'

'

'

'101 months

'

'

'

'89 months

'

'

'

'

'

'

'23 months

'

'

'

'

'

'

'76 months

'

'

'

'

'

'

'40 months

'

'

'

'

'

'

'39 months

'

'

'

'

'

'

'70 months

'

'

'

'

'

'

'67 months

'

'

'

'

'

'

'111 months

'

'

'

'

'

'

Proved Developed Reserves (Volume)

'

492,200,000,000

3,300,000

9,400,000

'

57,100,000,000

1,800,000

6,300,000

'

138,000,000,000

89,500,000,000

1,700,000

1,100,000

4,800,000

3,100,000

'

390,000,000,000

112,000,000,000

0

0

0

0

'

44,000,000,000

22,600,000,000

300,000

200,000

0

0

'

67,000,000,000

18,700,000,000

200,000

100,000

0

0

'

95,000,000,000

27,200,000,000

500,000

100,000

0

0

'

93,000,000,000

33,000,000,000

0

0

0

0

'

94,000,000,000

23,100,000,000

0

0

0

0

'

208,000,000,000

109,000,000,000

0

0

0

0

Proved Developed Reserves (Energy)

568,300,000,000

'

'

'

106,100,000,000

'

'

'

114,400,000,000

'

'

'

'

'

'

112,000,000,000

'

'

'

'

'

'

23,600,000,000

'

'

'

'

'

'

19,000,000,000

'

'

'

'

'

'

28,100,000,000

'

'

'

'

'

'

33,000,000,000

'

'

'

'

'

'

23,100,000,000

'

'

'

'

'

'

109,000,000,000

'

'

'

'

'

'

Divestitures_Narrative_Details

Divestitures Narrative (Details) (USD $)

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Jul. 11, 2013

Sep. 30, 2012

Sep. 30, 2012

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2010

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2013

Dec. 31, 2011

Feb. 28, 2011

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Permian Basin [Member]

XTO Energy Inc. [Member]

Utica [Member]

Payment at Closing [Member]

Payment at Closing [Member]

Payment Remaining [Member]

Subsequent Payment [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Scenario, Forecast [Member]

Excluding Joint Ventures [Member]

Excluding Joint Ventures [Member]

JV Marcellus, Barnett and Utica

JV Marcellus, Barnett and Utica

VPP 7 Permian Basin [Member]

VPP 7 Permian Basin [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

Corporate Joint Venture [Member]

JV Utica

JV Niobrara

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

JV Mississippi Lime

Corporate VPP [Member]

acre

acre

acre

acre

Haynesville Shale [Member]

Northern Eagle Ford Shale [Member]

Northern Eagle Ford Shale [Member]

Northern Eagle Ford Shale [Member]

Haynesville Shale [Member]

Oil [Member]

Natural Gas [Member]

Mcfe

acre

acre

Payment at Closing [Member]

Payment Remaining [Member]

Payment Remaining [Member]

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

Boe

Mcf

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Maximum working interest percentage allowed

2.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gas and Oil Area, Developed, Net

'

'

9,600

55,000

'

60,000

72,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

850,000

'

'

425,000

'

'

'

'

'

Proceeds from divestitures of proved and unproved properties

$2,789,000,000

$2,445,000,000

'

'

$376,000,000

$572,000,000

$358,000,000

$257,000,000

$617,000,000

$64,000,000

$4,000,000

$32,000,000

'

'

$800,000,000

$180,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

50.00%

'

'

'

'

'

Proved Developed Reserves (Energy)

'

'

'

'

'

'

'

'

'

'

'

'

22

'

'

'

'

'

'

28,000,000

'

'

'

'

'

'

'

'

'

'

'

Proceeds from Divestiture of Interest in Joint Venture

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

48,000,000

228,000,000

313,000,000

'

8,049,000,000

'

'

610,000,000

570,000,000

1,020,000,000

949,000,000

71,000,000

71,000,000

90,000,000

'

Percentage of Total Payment by Joint Venture Partner

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

93.00%

'

7.00%

'

'

Proved Developed Reserves (Volume)

'

'

'

'

'

'

'

'

'

'

'

'

'

251

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of Joint Ventures

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

8

'

'

'

'

'

'

'

'

'

'

Total Drilling Carries

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

9,035,000,000

'

'

1,422,000,000

697,000,000

0

'

'

'

'

'

Oil And Gas Benefit From Drilling Carries

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

669,000,000

655,000,000

'

'

'

'

'

'

'

'

'

Gain (Loss) on Sale of Other Assets

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$0

Investments_Schedule_of_Invest

Investments Schedule of Investments Table (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	0.00%	'
Investments	$615	$728
FTS International, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	30.00%	'
Equity Method Investments	318	298
Chaparral Energy, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	20.00%	'
Equity Method Investments	145	141
Sundrop Fuels, Inc.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	50.00%	'
Equity Method Investments	97	111
Twin Eagle Resources Management, LLC	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	30.00%	'
Equity Method Investments	30	34
Maalt Specialized Bulk, LLC	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Equity Method Investment, Ownership Percentage	49.00%	'
Equity Method Investments	13	13
Clean Energy Fuels Corp.	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Cost method percentage approximate owned	0.00%	'
Fair Value Method Investment Ownership Percentage	0.00%	'
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%	'
Fair Value Method Investments	0	8
Other Investment Companies [Member]	'	'
Schedule of Equity Method Investments [Line Items]	'	'
Cost Method Investments	$12	$11

Investments_Narrative_Details

Investments Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Frac Tech Holdings, L.L.C.

Chaparral Energy, Inc.

Sundrop Fuels, Inc.

Twin Eagle Resources Management, LLC

Maalt Specialized Bulk, LLC

Clean Energy Fuels Corp.

Clean Energy Fuels Corp.

Clean Energy Fuels Corp.

Clean Energy Fuels Corp.

Gastar Exploration Ltd.

Other Investments

Schedule of Equity Method Investments [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Cost method percentage approximate owned

'

'

'

'

'

'

'

'

'

0.00%

'

0.00%

'

'

'

Other Commitment, Due in Next Twelve Months

'

'

'

'

$3,000,000

'

'

'

'

'

'

'

'

'

'

Positive equity method adjustments

'

'

'

'

17,000,000

11,000,000

14,000,000

4,000,000

0

'

'

'

'

'

'

Equity method accretion adjustments

'

'

'

'

34,000,000

'

'

'

'

'

'

'

'

'

'

Excess carrying value of investment over underlying equity in net assets

'

'

'

'

333,000,000

49,000,000

53,000,000

'

'

'

'

'

'

'

'

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

'

'

'

'

31,000,000

'

'

'

'

'

'

'

'

'

'

Goodwill, Not Allocated, Amount

'

'

'

'

265,000,000

'

'

'

'

'

'

'

'

'

'

Property, Plant and Equipment, Useful Life

'

'

'

'

'P9Y

'

'

'

'

'

'

'

'

'

'

Depreciation

'

'

'

'

'

4,000,000

'

'

'

'

'

'

'

'

'

Equity method depreciation adjustments

'

'

'

'

'

3,000,000

'

'

'

'

'

'

'

'

'

Sale of Stock, Consideration Received on Transaction

'

'

'

'

'

'

'

'

'

'

'

13,000,000

'

10,000,000

6,000,000

Impairment of investment

0

0

10,000,000

0

'

'

'

'

'

15,000,000

'

'

'

'

'

Cost Method Investments

'

'

'

'

'

'

'

'

'

0

'

0

100,000,000

'

'

Proceeds from Cost Method Investment

'

'

'

'

'

'

'

'

'

'

85,000,000

'

'

'

'

Other Commitment

50,000,000

'

50,000,000

'

'

'

'

'

'

50,000,000

'

50,000,000

'

'

'

Gains (losses) on sales of investments

'

'

'

'

'

'

'

'

'

$3,000,000

'

'

'

'

$5,000,000

Variable_Interest_Entities_Nar

Variable Interest Entities Narrative (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013
Variable Interest Entity [Line Items]	'
Other Commitment	50
Chesapeake Granite Wash Trust | Consolidated Entities	'
Variable Interest Entity [Line Items]	'
Consolidation Net Oil and Gas Property Assets	337
Other current liabilities attributable to our VIEs	24
Cash and cash equivalents attributable to our VIEs	1
Short-term derivative liabilities attributable to our VIEs	7
Long-term derivative liabilities attributable to our VIEs	1
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member]	'
Variable Interest Entity [Line Items]	'
Percentage of acquisition	10.00%
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member] | Minimum	'
Variable Interest Entity [Line Items]	'
Percentage of royalty minimum	7.00%
Mineral Acquisition Company I, L.P. | Corporate Ownership Requirement [Member] | Maximum	'
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

Net_Gains_Losses_on_Sales_of_F2

Net Gains (Losses) on Sales of Fixed Assets Net Gains (Losses) on Sales of Fixed Assets Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Property, Plant and Equipment [Line Items]	'	'	'	'
Net (gains) losses on sales of fixed assets	($132)	$7	($290)	$5
Gas Gathering and Processing Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net (gains) losses on sales of fixed assets	-132	-7	-311	-8
Exploration and Production Equipment [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net (gains) losses on sales of fixed assets	0	10	1	12
Land and Building [Member]	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net (gains) losses on sales of fixed assets	1	0	24	0
Other Assets	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'
Net (gains) losses on sales of fixed assets	($1)	$4	($4)	$1

Net_Gains_on_Sales_of_Fixed_As

Net Gains on Sales of Fixed Assets Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Gain (Loss) on Sale of Property Plant Equipment	$132	($7)	$290	($5)
Sale to MarkWest Oklahoma Gas Company L.L.C. [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	252	'
Gas Gathering and Processing Equipment [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Gain (Loss) on Sale of Property Plant Equipment	132	7	311	8
Gas Gathering and Processing Equipment [Member] | Sale to SemGas, L.P. [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	306	'	'	'
Gain (Loss) on Sale of Property Plant Equipment	'	'	141	'
Gas Gathering and Processing Equipment [Member] | Sale to MarkWest Oklahoma Gas Company L.L.C. [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Gain (Loss) on Sale of Property Plant Equipment	'	'	105	'
Gas Gathering and Processing Equipment [Member] | Sale to Western Gas Partners, LP [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Proceeds from Sale of Property, Plant, and Equipment	'	'	134	'
Gain (Loss) on Sale of Property Plant Equipment	'	'	$55	'

Impairment_Table_Details

Impairment Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	$85	$38	$343	$281
Land and Building [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	8	7	247	227
Exploration and Production Equipment [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	24	31	27	54
Gas Gathering and Processing Equipment [Member]	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	21	0	22	0
Other Assets	'	'	'	'
Impaired Long-Lived Assets Held and Used [Line Items]	'	'	'	'
Impairments of fixed assets and other	$32	$0	$47	$0

Impairments_Narrative_Details

Impairments Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of natural gas and oil properties	$0	$3,315	$0	$3,315
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	44	'	'	'
Effects of Cash Flow Hedges Considered in Calculation Ceiling Limitation, Amount	279	'	279	'
Repurchase of Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Equipment Owned	'	22	'	'
Land and Building [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	'	'	28	227
Land and Building [Member] | Assets Held-for-sale [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	'	'	31	'
Disposal Group, Not Discontinued Operation, Loss (Gain) on Write-down	'	'	138	'
Drilling Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	24	6	'	20
Equipment Owned	8	'	'	'
Payments to Acquire Property, Plant, and Equipment	'	'	'	53
Drilling Rigs [Member] | Repurchase of Rigs [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	'	25	'	'
Drilling Rigs [Member] | Assets Held-for-sale [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Equipment Owned	7	'	'	'
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] | Assets Held-for-sale [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	26	'	'	'
Gas Gathering and Processing Equipment [Member] | Assets Held-for-Use [Member]	'	'	'	'
Significant Acquisitions and Disposals [Line Items]	'	'	'	'
Impairment of Long-Lived Assets to be Disposed of	$18	'	'	'

Restructuring_and_Other_Termin1

Restructuring and Other Termination Benefits Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring Charges	$63	$3	$203	$4
Other Benefit Total [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	28	3	42	4
Workforce Reduction Plan [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	31	0	31	0
Workforce Reduction Plan [Member] | Salary Expense [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Restructuring and Related Cost, Incurred Cost	5	0	5	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	25	0	25	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	1	'
Ceo Aubrey K Mcclendon [Member] | McClendon Benefit Total [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	3	0	67	0
Ceo Aubrey K Mcclendon [Member] | Cash Salary and Bonus Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	11	0
Ceo Aubrey K Mcclendon [Member] | Claw-Back Bonus [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	11	0
Ceo Aubrey K Mcclendon [Member] | Acceleration of Restricted Stock Awards [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	22	0
Ceo Aubrey K Mcclendon [Member] | Acceleration of Performance Shares [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	3	0	16	0
Ceo Aubrey K Mcclendon [Member] | Other Costs Associated with Retirement [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	7	0
VSP Program | VSP Benefit Total [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	1	0	63	0
VSP Program | Cash Salary and Bonus Costs [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	0	0	33	0
VSP Program | Acceleration of Restricted Stock Awards [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	1	0	28	0
VSP Program | Other Costs Associated with Retirement [Member]	'	'	'	'
Deferred Compensation Arrangement with Individual, Postretirement Benefits [Line Items]	'	'	'	'
Severance Costs	$0	$0	$2	$0

Restructuring_and_Other_Termin2

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

3 Months Ended

9 Months Ended

3 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Feb. 07, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Other Benefit Total [Member]

Other Benefit Total [Member]

Other Benefit Total [Member]

Other Benefit Total [Member]

One-time Termination Benefits [Member]

One-time Termination Benefits [Member]

One-time Termination Benefits [Member]

VSP Program

VSP Program

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

Workforce Reduction Plan [Member]

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

Ceo Aubrey K Mcclendon [Member]

VSP Program

VSP Program

VSP Program

VSP Program

Expected Total [Member]

Current Liabilities [Member]

Scenario, Forecast [Member]

McClendon Benefit Total [Member]

McClendon Benefit Total [Member]

McClendon Benefit Total [Member]

McClendon Benefit Total [Member]

VSP Benefit Total [Member]

VSP Benefit Total [Member]

VSP Benefit Total [Member]

VSP Benefit Total [Member]

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and Related Cost, Number of Positions Eliminated

900

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and Related Cost, Expected Cost

'

'

'

'

'

$70

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and Related Cost, Incurred Cost

'

'

'

'

'

'

'

'

'

'

31

0

31

0

'

'

'

'

'

'

'

'

Severance Costs

'

28

3

42

4

'

'

'

'

'

'

'

'

'

3

0

67

0

1

0

63

0

Payments for Restructuring

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Restructuring and Related Cost, Expected Cost Remaining

'

'

'

'

'

'

'

$39

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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 $)	Sep. 30, 2013	Dec. 31, 2012
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Total derivatives	($676)	($979)
Total	-672	-954
Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	126	115
Commodity liabilities	-709	-1,039
Interest rate contract	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Interest rate liabilities	-88	-35
Foreign currency contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Foreign currency liabilities	-5	-20
Other Current Assets [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Other current assets	93	4
Other Current Liabilities [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	-89	'
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	4	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	93	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	-89	'
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]	'	'
Obligations, fair value disclosure	'	0
Total derivatives	-91	37
Total	-91	37
Fair Value, Inputs, Level 2 [Member] | Commodity contracts	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Commodity assets	105	105
Commodity liabilities	-103	-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	-88	-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	-5	-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 3 [Member]	'	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'	'
Obligations, fair value disclosure	'	0
Total derivatives	-585	-1,016
Total	-585	-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	21	10
Commodity liabilities	-606	-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_Measurements_Unobse

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

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2012

Dec. 31, 2011

Sep. 29, 2013

Sep. 29, 2012

Sep. 30, 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]

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

Commodity contracts

Interest rate contract

Interest rate contract

Interest rate contract

Interest rate contract

Interest rate contract

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Beginning balance

($2)

'

'

'

'

'

'

($585)

($1,016)

($1,073)

($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

'

338

525

-1

4

338

525

'

'

'

'

-1

4

'

'

'

Sales

'

'

'

'

'

0

0

'

'

'

'

1

-6

'

'

'

Settlements

'

'

'

'

'

93

56

'

'

'

'

0

0

'

'

'

Ending balance

-2

'

'

'

'

'

'

-585

-1,016

-1,073

-1,654

'

'

0

0

0

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

'

$327

$370

$0

($2)

'

'

'

'

'

'

'

'

'

'

'

Fair_Value_Measurements_Level_

Fair Value Measurements Level 3 Table and Phantom (Details) (USD $)	9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2013
Crude Oil [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Unobservable Input	'Oil price volatility curves
Weighted average of price volatility curve, percentage	16.44%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	($369)
Crude Oil [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	9.94%
Crude Oil [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	25.79%
Crude Oil [Member] | Basis Swap [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Unobservable Input	'Physical pricing point forward curves
Weighted Average Of Price Forward Curve	$4.33
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	1
Crude Oil [Member] | Basis Swap [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	3.03
Crude Oil [Member] | Basis Swap [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	4.65
Natural Gas [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Unobservable Input	'Natural gas price volatility curves
Weighted average of price volatility curve, percentage	22.10%
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	-215
Natural Gas [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	20.08%
Natural Gas [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Volatility Curve	34.86%
Natural Gas [Member] | Basis Swap [Member]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Unobservable Input	'Physical pricing point forward curves
Weighted Average Of Price Forward Curve	($0.36)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	($2)
Natural Gas [Member] | Basis Swap [Member] | Minimum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	-1.64
Natural Gas [Member] | Basis Swap [Member] | Maximum	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share [Line Items]	'
Price Forward Curve	0

Fair_Value_Measurements_Compar

Fair Value Measurements Compared to Carrying Value Excluding Impact of Interest Rate Derivatives Table (Details) (USD $)	Sep. 30, 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
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	10,470	9,759
Carrying Amount | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	2,252	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	11,333	10,457
Estimated Fair Value | Fair Value, Inputs, Level 2 [Member]	'	'
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]	'	'
Long-term Debt	$2,241	$2,284

Segment_Reporting_Table_Detail

Segment Reporting Table (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$4,867	$2,970	$12,965	$8,778	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	387	-3,231	1,561	-1,537	'
TOTAL ASSETS	42,288	'	42,288	'	41,611
Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	1,586	1,437	5,444	4,622	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	430	-3,073	654	-1,896	'
TOTAL ASSETS	35,919	'	35,919	'	37,004
Marketing, Gathering And Compression	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	3,032	1,381	6,871	3,710	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	128	120	395	1,279	'
TOTAL ASSETS	2,323	'	2,323	'	2,291
Oilfield Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	245	152	636	446	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	-37	-2	-12	96	'
TOTAL ASSETS	1,981	'	1,981	'	2,115
Other Operations	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	4	0	14	0	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	-48	-152	808	-654	'
TOTAL ASSETS	5,014	'	5,014	'	2,529
Reportable Subsegments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	4,867	2,970	12,965	8,778	'
Intersubsegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Operating Segments [Member] | Reportable Subsegments [Member] | Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	1,586	1,437	5,444	4,622	'
Operating Segments [Member] | Reportable Subsegments [Member] | Marketing, Gathering And Compression	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	5,034	2,922	12,553	7,587	'
Operating Segments [Member] | Reportable Subsegments [Member] | Oilfield Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	551	482	1,677	1,434	'
Operating Segments [Member] | Reportable Subsegments [Member] | Other Operations	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	4	0	27	0	'
Intersegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Extraordinary Items, Noncontrolling Interest	-86	-124	-284	-362	'
TOTAL ASSETS	-2,949	'	-2,949	'	-2,328
Intersegment Eliminations [Member] | Exploration and Production	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	0	0	'
Intersegment Eliminations [Member] | Marketing, Gathering And Compression	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,002	-1,541	-5,682	-3,877	'
Intersegment Eliminations [Member] | Oilfield Services	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-306	-330	-1,041	-988	'
Intersegment Eliminations [Member] | Other Operations	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	0	0	-13	0	'
Intersegment Eliminations [Member] | Reportable Subsegments [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	-2,308	-1,871	-6,736	-4,865	'
Intersegment Eliminations [Member] | Intersubsegment Eliminations [Member]	'	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'	'
Revenues	$2,308	$1,871	$6,736	$4,865	'

Segment_Information_Narrative_

Segment Information Narrative (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
			Segment
Segment Reporting Information [Line Items]	'	'	'	'
Number of reportable segments	'	'	3	'
Revenues	($4,867)	($2,970)	($12,965)	($8,778)
Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	0	0	0	0
Marketing, Gathering And Compression	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	-3,032	-1,381	-6,871	-3,710
Marketing, Gathering And Compression | Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	2,002	1,541	5,682	3,877
Oilfield Services	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	-245	-152	-636	-446
Oilfield Services | Intersegment Eliminations [Member]	'	'	'	'
Segment Reporting Information [Line Items]	'	'	'	'
Revenues	$306	$330	$1,041	$988

Condensed_Consolidating_Balanc

Condensed Consolidating Balance Sheet (Details) (USD $)	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	$987	$287	$142	$351
Restricted cash	75	111	'	'
Other	2,932	2,546	'	'
Current assets held for sale	0	4	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	3,994	2,948	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	32,519	31,918	'	'
Other property and equipment, net	4,005	4,615	'	'
Property and equipment held for sale, net	597	634	'	'
Total Property and Equipment, Net	37,121	37,167	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	1,173	1,496	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	42,288	41,611	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,678	6,245	'	'
Current liabilities held for sale	0	21	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	5,678	6,266	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	12,736	12,157	'	'
Deferred income tax liabilities	3,423	2,807	'	'
Other long-term liabilities	2,103	2,485	'	'
Total Long-Term Liabilities	18,262	17,449	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,196	15,569	'	'
Noncontrolling interests	2,152	2,327	'	'
Total Equity	18,348	17,896	17,691	'
TOTAL LIABILITIES AND EQUITY	42,288	41,611	'	'
Parent	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	966	228	61	1
Restricted cash	0	0	'	'
Other	104	1	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	25,863	25,356	'	'
Total Current Assets	26,933	25,585	'	'
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	114	217	'	'
Investments in subsidiaries and intercompany advances	2,211	2,241	'	'
TOTAL ASSETS	29,258	28,043	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	242	789	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	0	0	'	'
Total Current Liabilities	242	789	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	11,801	11,089	'	'
Deferred income tax liabilities	638	361	'	'
Other long-term liabilities	381	235	'	'
Total Long-Term Liabilities	12,820	11,685	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	16,196	15,569	'	'
Noncontrolling interests	0	0	'	'
Total Equity	16,196	15,569	'	'
TOTAL LIABILITIES AND EQUITY	29,258	28,043	'	'
Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	0	0	0	0
Restricted cash	0	0	'	'
Other	2,606	2,378	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	2,606	2,378	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	29,245	29,083	'	'
Other property and equipment, net	2,561	3,066	'	'
Property and equipment held for sale, net	571	255	'	'
Total Property and Equipment, Net	32,377	32,404	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	1,316	1,396	'	'
Investments in subsidiaries and intercompany advances	-238	-186	'	'
TOTAL ASSETS	36,061	35,992	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	5,427	5,377	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	24,740	24,166	'	'
Total Current Liabilities	30,167	29,543	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	2,397	2,425	'	'
Other long-term liabilities	1,286	1,783	'	'
Total Long-Term Liabilities	3,683	4,208	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	2,211	2,241	'	'
Noncontrolling interests	0	0	'	'
Total Equity	2,211	2,241	'	'
TOTAL LIABILITIES AND EQUITY	36,061	35,992	'	'
Non-Guarantor Subsidiaries	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	14	59	81	350
Restricted cash	82	111	'	'
Other	645	512	'	'
Current assets held for sale	0	4	'	'
Intercompany receivable, net	0	0	'	'
Total Current Assets	741	686	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	3,123	3,057	'	'
Other property and equipment, net	1,445	1,549	'	'
Property and equipment held for sale, net	26	379	'	'
Total Property and Equipment, Net	4,594	4,985	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	115	261	'	'
Investments in subsidiaries and intercompany advances	0	0	'	'
TOTAL ASSETS	5,450	5,932	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	431	424	'	'
Current liabilities held for sale	'	21	'	'
Intercompany payable, net	1,279	1,312	'	'
Total Current Liabilities	1,710	1,757	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	935	1,068	'	'
Deferred income tax liabilities	60	127	'	'
Other long-term liabilities	900	839	'	'
Total Long-Term Liabilities	1,895	2,034	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	1,845	2,141	'	'
Noncontrolling interests	0	0	'	'
Total Equity	1,845	2,141	'	'
TOTAL LIABILITIES AND EQUITY	5,450	5,932	'	'
Eliminations	'	'	'	'
CURRENT ASSETS:	'	'	'	'
Cash and cash equivalents	7	0	0	0
Restricted cash	-7	0	'	'
Other	-423	-345	'	'
Current assets held for sale	0	0	'	'
Intercompany receivable, net	-25,863	-25,356	'	'
Total Current Assets	-26,286	-25,701	'	'
PROPERTY AND EQUIPMENT:	'	'	'	'
Natural gas and oil properties, at cost based on full cost accounting, net	151	-222	'	'
Other property and equipment, net	-1	0	'	'
Property and equipment held for sale, net	0	0	'	'
Total Property and Equipment, Net	150	-222	'	'
LONG-TERM ASSETS:	'	'	'	'
Other assets	-372	-378	'	'
Investments in subsidiaries and intercompany advances	-1,973	-2,055	'	'
TOTAL ASSETS	-28,481	-28,356	'	'
CURRENT LIABILITIES:	'	'	'	'
Current liabilities	-422	-345	'	'
Current liabilities held for sale	'	0	'	'
Intercompany payable, net	-26,019	-25,478	'	'
Total Current Liabilities	-26,441	-25,823	'	'
LONG-TERM LIABILITIES:	'	'	'	'
Long-term debt, net	0	0	'	'
Deferred income tax liabilities	328	-106	'	'
Other long-term liabilities	-464	-372	'	'
Total Long-Term Liabilities	-136	-478	'	'
EQUITY:	'	'	'	'
Chesapeake stockholders’ equity	-4,056	-4,382	'	'
Noncontrolling interests	2,152	2,327	'	'
Total Equity	-1,904	-2,055	'	'
TOTAL LIABILITIES AND EQUITY	($28,481)	($28,356)	'	'

Condensed_Consolidating_Statem

Condensed Consolidating Statement Of Operations (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
REVENUES	'	'	'	'
Natural gas, oil and NGL	$1,586	$1,437	$5,444	$4,622
Marketing, gathering and compression	3,032	1,381	6,871	3,710
Oilfield services	249	152	650	446
Total Revenues	4,867	2,970	12,965	8,778
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	282	320	877	1,005
Production taxes	62	53	173	141
Marketing, gathering and compression	3,009	1,339	6,781	3,631
Oilfield services	211	116	543	321
General and administrative	120	145	336	436
Restructuring Charges	63	3	203	4
Natural gas, oil and NGL depreciation, depletion and amortization	652	762	1,945	1,856
Depreciation and amortization of other assets	79	66	234	233
Impairment of natural gas and oil properties	0	3,315	0	3,315
Impairments of fixed assets and other	85	38	343	281
Net (gains) losses on sales of fixed assets	-132	7	-290	5
Total Operating Expenses	4,431	6,164	11,145	11,228
INCOME (LOSS) FROM OPERATIONS	436	-3,194	1,820	-2,450
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-40	-36	-164	-63
Losses on investments	-22	-23	-26	-87
Impairment of investment	0	0	-10	0
Gains (losses) on sales of investments	3	31	-7	1,061
Losses on purchases of debt	0	0	-70	0
Other income (expense)	10	-9	18	2
Equity in net earnings of subsidiary	0	0	0	0
Total Other Income (Expense)	-49	-37	-259	913
INCOME (LOSS) BEFORE INCOME TAXES	387	-3,231	1,561	-1,537
INCOME TAX EXPENSE (BENEFIT)	147	-1,260	594	-599
NET INCOME (LOSS)	240	-1,971	967	-938
Net income attributable to noncontrolling interests	-38	-41	-127	-131
Net income (loss) attributable to Chesapeake	202	-2,012	840	-1,069
Other Comprehensive Income (Loss), Net of Tax	1	-6	13	-22
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	203	-2,018	853	-1,091
Parent	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services	0	0	0	0
Total Revenues	0	0	0	0
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	0	0	0	0
Production taxes	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services	0	0	0	0
General and administrative	0	0	0	0
Restructuring Charges	0	0	0	0
Natural gas, oil and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	0	0	0	0
Impairment of natural gas and oil properties	0	0	0	0
Impairments of fixed assets and other	0	0	0	0
Net (gains) losses on sales of fixed assets	0	0	0	0
Total Operating Expenses	0	0	0	0
INCOME (LOSS) FROM OPERATIONS	0	0	0	0
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-207	-289	-703	-682
Losses on investments	0	0	0	0
Impairment of investment	0	'	0	'
Gains (losses) on sales of investments	0	0	0	0
Losses on purchases of debt	'	'	-70	'
Other income (expense)	208	286	651	667
Equity in net earnings of subsidiary	201	-2,010	916	-1,060
Total Other Income (Expense)	202	-2,013	794	-1,075
INCOME (LOSS) BEFORE INCOME TAXES	202	-2,013	794	-1,075
INCOME TAX EXPENSE (BENEFIT)	0	-1	-46	-6
NET INCOME (LOSS)	202	-2,012	840	-1,069
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	202	-2,012	840	-1,069
Other Comprehensive Income (Loss), Net of Tax	2	3	2	3
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	204	-2,009	842	-1,066
Guarantor Subsidiaries	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	1,400	1,357	4,962	4,410
Marketing, gathering and compression	3,031	1,319	6,861	3,555
Oilfield services	0	0	0	0
Total Revenues	4,431	2,676	11,823	7,965
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	268	311	838	989
Production taxes	60	51	167	137
Marketing, gathering and compression	3,009	1,310	6,776	3,549
Oilfield services	23	80	70	141
General and administrative	97	108	264	343
Restructuring Charges	63	2	200	3
Natural gas, oil and NGL depreciation, depletion and amortization	591	716	1,771	1,761
Depreciation and amortization of other assets	43	43	137	132
Impairment of natural gas and oil properties	0	3,167	0	3,167
Impairments of fixed assets and other	56	8	307	227
Net (gains) losses on sales of fixed assets	-133	4	-291	2
Total Operating Expenses	4,077	5,800	10,239	10,451
INCOME (LOSS) FROM OPERATIONS	354	-3,124	1,584	-2,486
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-27	-18	-70	-3
Losses on investments	-22	-23	-26	-142
Impairment of investment	0	'	-10	'
Gains (losses) on sales of investments	3	0	-7	1,030
Losses on purchases of debt	'	'	0	'
Other income (expense)	44	79	120	166
Equity in net earnings of subsidiary	-75	-127	-221	-179
Total Other Income (Expense)	-77	-89	-214	872
INCOME (LOSS) BEFORE INCOME TAXES	277	-3,213	1,370	-1,614
INCOME TAX EXPENSE (BENEFIT)	134	-1,204	605	-559
NET INCOME (LOSS)	143	-2,009	765	-1,055
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	143	-2,009	765	-1,055
Other Comprehensive Income (Loss), Net of Tax	1	-7	12	-25
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	144	-2,016	777	-1,080
Non-Guarantor Subsidiaries	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	185	79	473	209
Marketing, gathering and compression	1	62	10	155
Oilfield services	552	485	1,703	1,440
Total Revenues	738	626	2,186	1,804
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	14	9	39	16
Production taxes	2	2	6	4
Marketing, gathering and compression	0	29	5	82
Oilfield services	460	361	1,362	1,029
General and administrative	24	37	73	93
Restructuring Charges	0	1	3	1
Natural gas, oil and NGL depreciation, depletion and amortization	61	46	174	95
Depreciation and amortization of other assets	74	58	218	205
Impairment of natural gas and oil properties	99	148	260	148
Impairments of fixed assets and other	29	30	36	54
Net (gains) losses on sales of fixed assets	0	3	0	3
Total Operating Expenses	763	724	2,176	1,730
INCOME (LOSS) FROM OPERATIONS	-25	-98	10	74
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	-21	-21	-63	-64
Losses on investments	0	0	0	55
Impairment of investment	-1	'	-1	'
Gains (losses) on sales of investments	0	31	0	31
Losses on purchases of debt	'	'	0	'
Other income (expense)	2	3	7	10
Equity in net earnings of subsidiary	0	0	0	0
Total Other Income (Expense)	-20	13	-57	32
INCOME (LOSS) BEFORE INCOME TAXES	-45	-85	-47	106
INCOME TAX EXPENSE (BENEFIT)	-17	-33	-18	41
NET INCOME (LOSS)	-28	-52	-29	65
Net income attributable to noncontrolling interests	0	0	0	0
Net income (loss) attributable to Chesapeake	-28	-52	-29	65
Other Comprehensive Income (Loss), Net of Tax	-2	-2	-1	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	-30	-54	-30	65
Eliminations	'	'	'	'
REVENUES	'	'	'	'
Natural gas, oil and NGL	1	1	9	3
Marketing, gathering and compression	0	0	0	0
Oilfield services	-303	-333	-1,053	-994
Total Revenues	-302	-332	-1,044	-991
OPERATING EXPENSES	'	'	'	'
Natural gas, oil and NGL production	0	0	0	0
Production taxes	0	0	0	0
Marketing, gathering and compression	0	0	0	0
Oilfield services	-272	-325	-889	-849
General and administrative	-1	0	-1	0
Restructuring Charges	0	0	0	0
Natural gas, oil and NGL depreciation, depletion and amortization	0	0	0	0
Depreciation and amortization of other assets	-38	-35	-121	-104
Impairment of natural gas and oil properties	-99	0	-260	0
Impairments of fixed assets and other	0	0	0	0
Net (gains) losses on sales of fixed assets	1	0	1	0
Total Operating Expenses	-409	-360	-1,270	-953
INCOME (LOSS) FROM OPERATIONS	107	28	226	-38
OTHER INCOME (EXPENSE):	'	'	'	'
Interest expense	215	292	672	686
Losses on investments	0	0	0	0
Impairment of investment	1	'	1	'
Gains (losses) on sales of investments	0	0	0	0
Losses on purchases of debt	'	'	0	'
Other income (expense)	-244	-377	-760	-841
Equity in net earnings of subsidiary	-126	2,137	-695	1,239
Total Other Income (Expense)	-154	2,052	-782	1,084
INCOME (LOSS) BEFORE INCOME TAXES	-47	2,080	-556	1,046
INCOME TAX EXPENSE (BENEFIT)	30	-22	53	-75
NET INCOME (LOSS)	-77	2,102	-609	1,121
Net income attributable to noncontrolling interests	-38	-41	-127	-131
Net income (loss) attributable to Chesapeake	-115	2,061	-736	990
Other Comprehensive Income (Loss), Net of Tax	0	0	0	0
COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO CHESAPEAKE	($115)	$2,061	($736)	$990

Condensed_Consolidating_Statem1

Condensed Consolidating Statements Of Cash Flows (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Condensed Financial Statements, Captions [Line Items]	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	$3,561	$1,978
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to proved and unproved properties	-5,281	-10,338
Proceeds from divestitures of proved and unproved properties	2,789	2,445
Additions to other property and equipment	-639	-1,916
Other investing activities	1,084	1,655
Net Cash Used In Investing Activities	-2,047	-8,154
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	7,136	13,986
Payments on credit facilities borrowings	-7,268	-13,614
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263
Proceeds from issuance of term loans, net of discount and offering costs	0	3,789
Cash paid to purchase debt	-2,116	0
Proceeds from sales of noncontrolling interests	5	1,056
Other financing activities	-845	-499
Intercompany advances, net	0	0
Net Cash Provided By (Used In) Financing Activities	-814	5,981
Change in cash and cash equivalents classified as current assets held for sale	0	-14
Net increase (decrease) in cash and cash equivalents	700	-209
Cash and cash equivalents, beginning of period	287	351
Cash and cash equivalents, end of period	987	142
Parent	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	0	0
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	0	0
Net Cash Used In Investing Activities	0	0
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	2,274	1,263
Proceeds from issuance of term loans, net of discount and offering costs	'	3,789
Cash paid to purchase debt	-2,116	'
Proceeds from sales of noncontrolling interests	0	0
Other financing activities	-374	-367
Intercompany advances, net	954	-4,618
Net Cash Provided By (Used In) Financing Activities	738	67
Change in cash and cash equivalents classified as current assets held for sale	'	-7
Net increase (decrease) in cash and cash equivalents	738	60
Cash and cash equivalents, beginning of period	228	1
Cash and cash equivalents, end of period	966	61
Guarantor Subsidiaries	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	3,232	2,779
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to proved and unproved properties	-4,642	-10,208
Proceeds from divestitures of proved and unproved properties	2,736	2,445
Additions to other property and equipment	-415	-577
Other investing activities	67	3,051
Net Cash Used In Investing Activities	-2,254	-5,289
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	6,311	12,116
Payments on credit facilities borrowings	-6,310	-12,051
Proceeds from issuance of senior notes, net of discount and offering costs	0	0
Proceeds from issuance of term loans, net of discount and offering costs	'	0
Cash paid to purchase debt	0	'
Proceeds from sales of noncontrolling interests	5	0
Other financing activities	-297	-154
Intercompany advances, net	-687	2,599
Net Cash Provided By (Used In) Financing Activities	-978	2,510
Change in cash and cash equivalents classified as current assets held for sale	'	0
Net increase (decrease) in cash and cash equivalents	0	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	0	0
Non-Guarantor Subsidiaries	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	362	200
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to proved and unproved properties	-639	-130
Proceeds from divestitures of proved and unproved properties	53	0
Additions to other property and equipment	-224	-1,339
Other investing activities	757	-158
Net Cash Used In Investing Activities	-53	-1,627
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	825	1,870
Payments on credit facilities borrowings	-958	-1,563
Proceeds from issuance of senior notes, net of discount and offering costs	0	0
Proceeds from issuance of term loans, net of discount and offering costs	'	0
Cash paid to purchase debt	0	'
Proceeds from sales of noncontrolling interests	0	1,056
Other financing activities	46	-2,217
Intercompany advances, net	-267	2,019
Net Cash Provided By (Used In) Financing Activities	-354	1,165
Change in cash and cash equivalents classified as current assets held for sale	'	-7
Net increase (decrease) in cash and cash equivalents	-45	-269
Cash and cash equivalents, beginning of period	59	350
Cash and cash equivalents, end of period	14	81
Eliminations	'	'
Condensed Financial Statements, Captions [Line Items]	'	'
CASH FLOWS FROM OPERATING ACTIVITIES	-33	-1,001
CASH FLOWS FROM INVESTING ACTIVITIES:	'	'
Additions to proved and unproved properties	0	0
Proceeds from divestitures of proved and unproved properties	0	0
Additions to other property and equipment	0	0
Other investing activities	260	-1,238
Net Cash Used In Investing Activities	260	-1,238
CASH FLOWS FROM FINANCING ACTIVITIES:	'	'
Proceeds from credit facilities borrowings	0	0
Payments on credit facilities borrowings	0	0
Proceeds from issuance of senior notes, net of discount and offering costs	0	0
Proceeds from issuance of term loans, net of discount and offering costs	'	0
Cash paid to purchase debt	0	'
Proceeds from sales of noncontrolling interests	0	0
Other financing activities	-220	2,239
Intercompany advances, net	0	0
Net Cash Provided By (Used In) Financing Activities	-220	2,239
Change in cash and cash equivalents classified as current assets held for sale	'	0
Net increase (decrease) in cash and cash equivalents	7	0
Cash and cash equivalents, beginning of period	0	0
Cash and cash equivalents, end of period	$7	$0

Subsequent_Events_Narrative_De

Subsequent Events Narrative (Details) (USD $)	Dec. 31, 2009	Dec. 31, 2013	Nov. 01, 2013	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
In Millions, unless otherwise specified	Property	Subsequent Event [Member]	Subsequent Event [Member]	Subsequent Event [Member]	Rigs	Rigs	Rigs	Minimum
		Barnett Lease [Member]	Barnett Lease [Member]	Scenario, Forecast [Member]		Subsequent Event [Member]	Subsequent Event [Member]	Rigs
			Property	Barnett Lease [Member]			Scenario, Forecast [Member]	Subsequent Event [Member]
								Scenario, Forecast [Member]
Subsequent Event [Line Items]	'	'	'	'	'	'	'	'
Number Of Real Estate Assets Financed	111	'	106	'	'	'	'	'
Lease Termination Costs	'	$257	'	'	'	'	'	'
Gain (Loss) on Contract Termination	'	'	'	120	'	'	'	'
Number of repurchased equipment	'	'	'	'	28	9	'	'
Operating Leases, Future Minimum Payments Due	'	'	'	'	239	'	'	58
Payments to Acquire Property, Plant, and Equipment	'	'	'	'	'	'	$70	'