Quicksilver Resources (KWK) 10-K/A 18 Mar 14 2013 FY Annual report (amended) Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2013	Feb. 28, 2014	Jun. 30, 2013
Document And Entity Information [Abstract]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'true	'	'
Amendment Description	'This Amendment No. 1 to the Quicksilver Resources Inc. Annual Report on Form 10-K for the fiscal year ended December 31, 2013, which was originally filed with the Securities and Exchange Commission on March 17, 2014 (the “Original Filing”), is being filed to correct inadvertent clerical errors in Exhibits 31.1, 31.2 and 32.1. No other change to the previously filed certifications is intended to be made by the filing of this Form 10-K/A, and this Form 10-K/A does not amend, update or change any other items or disclosures contained in the Original Filing. This Amendment No. 1 to the Form 10-K continues to speak as of the date of the Original Filing and does not reflect any events that occurred at any subsequent date.	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Entity Registrant Name	'QUICKSILVER RESOURCES INC	'	'
Entity Central Index Key	'0001060990	'	'
Current Fiscal Year End Date	'--12-31	'	'
Entity Filer Category	'Accelerated Filer	'	'
Entity Common Stock, Shares Outstanding	'	177,191,991	'
Entity Well-known Seasoned Issuer	'No	'	'
Entity Public Float	'	'	$209,743,745
Entity Current Reporting Status	'Yes	'	'
Entity Voluntary Filers	'No	'	'

Consolidated_Statements_of_Inc

Consolidated Statements of Income (Loss) and Comprehensive Income (Loss) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenue

'

'

'

'

'

'

'

'

'

'

'

Production

'

'

'

'

'

'

'

'

$463,491,000

$630,947,000

$800,543,000

Sales of purchased natural gas

'

'

'

'

'

'

'

'

64,913,000

62,405,000

86,645,000

Net derivative gains

'

'

'

'

'

'

'

'

29,928,000

11,444,000

51,780,000

Other

'

'

'

'

'

'

'

'

3,230,000

4,242,000

4,655,000

Total revenue

'

'

'

'

'

'

'

'

561,562,000

709,038,000

943,623,000

Operating expense

'

'

'

'

'

'

'

'

'

'

'

Lease operating

'

'

'

'

'

'

'

'

82,265,000

95,333,000

102,874,000

Gathering, processing and transportation

'

'

'

'

'

'

'

'

148,569,000

166,316,000

190,560,000

Production and ad valorem taxes

'

'

'

'

'

'

'

'

17,066,000

25,395,000

29,226,000

Cost of purchased natural gas

'

'

'

'

'

'

'

'

64,840,000

62,041,000

85,398,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

62,612,000

163,624,000

225,763,000

Impairment

'

'

'

'

'

'

'

'

1,863,000

2,625,928,000

107,059,000

General and administrative

'

'

'

'

'

'

'

'

55,306,000

75,697,000

79,582,000

Other operating

'

'

'

'

'

'

'

'

3,725,000

1,562,000

557,000

Total expense

'

'

'

'

'

'

'

'

436,246,000

3,215,896,000

821,019,000

Gain on Tokyo Gas Transaction

'

'

'

'

'

'

'

'

'

'

0

Crestwood earn-out

'

'

'

'

'

'

'

'

'

'

0

Operating income (loss)

13,575,000

[1]

60,049,000

[2]

394,894,000

[3]

-3,874,000

-468,213,000

[4]

-576,551,000

[5]

-1,153,012,000

[6]

-267,985,000

[7]

464,644,000

-2,465,761,000

122,604,000

Loss from earnings of BBEP

'

'

'

'

'

'

'

'

0

0

-8,439,000

Other income (expense) - net

'

'

'

'

'

'

'

'

-17,384,000

1,108,000

219,768,000

Fortune Creek accretion

'

'

'

'

'

'

'

'

-19,245,000

-19,472,000

0

Interest expense

'

'

'

'

'

'

'

'

-251,847,000

-164,051,000

-186,024,000

Income (loss) before income taxes

'

'

'

'

'

'

'

'

176,168,000

-2,648,176,000

147,909,000

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-14,550,000

295,570,000

-57,863,000

Net income (loss)

'

'

'

'

'

'

'

'

161,618,000

-2,352,606,000

90,046,000

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

'

'

'

Net change in derivative fair value - net of income tax

'

'

'

'

'

'

'

'

0

74,384,000

156,160,000

Foreign currency translation adjustment

'

'

'

'

'

'

'

'

-4,681,000

412,000

-13,364,000

Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax

'

'

'

'

'

'

'

'

-46,931,000

-128,161,000

-58,125,000

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-51,612,000

-53,365,000

84,671,000

Comprehensive income (loss)

'

'

'

'

'

'

'

'

110,006,000

-2,405,971,000

174,717,000

Earnings (loss) per common share - basic

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

($13.83)

$0.53

Earnings (loss) per common share - diluted

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

[8]

($13.83)

[8]

$0.52

[8]

Tokyo Gas [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating expense

'

'

'

'

'

'

'

'

'

'

'

Gain on Tokyo Gas Transaction

'

'

333,200,000

'

'

'

'

'

339,328,000

0

0

Crestwood earn-out

'

'

'

'

'

'

'

'

339,328,000

'

'

kwk_CrestwoodLP [Member]

'

'

'

'

'

'

'

'

'

'

'

Operating expense

'

'

'

'

'

'

'

'

'

'

'

Crestwood earn-out

'

'

'

'

'

'

'

'

$0

$41,097,000

$0

[1]

Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

[2]

Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR

[3]

Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

[4]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[5]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[6]

Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

[7]

Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

[8]

For 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
In Thousands, unless otherwise specified
Current assets	'	'	'	'
Cash and cash equivalents	$89,103	$4,951	$13,146	$54,937
Marketable securities	166,343	0	'	'
Cash, Cash Equivalents, and Short-term Investments	255,446	4,951	'	'
Accounts receivable - net of allowance for doubtful accounts	58,645	64,149	'	'
Derivative assets at fair value	57,523	113,367	'	'
Other current assets	22,346	25,046	'	'
Total current assets	393,960	207,513	'	'
Property, plant and equipment - net	'	'	'	'
Oil and gas properties, full cost method (including unevaluated costs of $221,605 and $307,267, respectively)	640,443	780,960	'	'
Other property and equipment	220,362	248,098	'	'
Property, plant and equipment - net	860,805	1,029,058	'	'
Derivative assets at fair value	73,357	105,270	'	'
Other assets	41,604	39,947	'	'
Total assets	1,369,726	1,381,788	'	'
Current liabilities	'	'	'	'
Accounts payable	28,822	37,131	'	'
Accrued liabilities	102,850	130,660	'	'
Derivative liabilities at fair value	3,125	0	'	'
Total current liabilities	134,797	167,791	'	'
Long-term debt	1,988,946	2,063,206	'	'
Partnership liability	126,132	130,912	'	'
Asset retirement obligations	106,256	115,949	'	'
Derivative liabilities at fair value	323	17,485	'	'
Other liabilities	19,242	19,242	'	'
Stockholders' equity	'	'	'	'
Preferred stock, par value $0.01, 10,000,000 shares authorized, none outstanding	0	0	'	'
Common stock, $0.01 par value, 400,000,000 shares authorized, and 183,994,879 and 179,015,118 shares issued, respectively	1,840	1,790	'	'
Additional paid in capital	770,092	751,394	'	'
Treasury stock of 6,698,640 and 5,921,102 shares, respectively	-51,422	-49,495	'	'
Accumulated other comprehensive income	109,881	161,493	'	'
Retained deficit	-1,836,361	-1,997,979	'	'
Total stockholders' equity	-1,005,970	-1,132,797	'	'
Total liabilities and stockholders' equity	$1,369,726	$1,381,788	'	'

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Unevaluated costs of oil and gas properties	$221,605	$307,267
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	10,000,000	10,000,000
Preferred stock, shares outstanding	0	0
Common stock, par value	$0.01	$0.01
Common stock, shares authorized	400,000,000	400,000,000
Common stock, shares issued	183,994,879	179,015,118
Treasury stock, shares	6,698,640	5,921,102

Consolidated_Statements_Of_Equ

Consolidated Statements Of Equity (USD $)	Total	Common Stock [Member]	Additional Paid-in Capital [Member]	Treasury Stock [Member]	Accumulated Other Comprehensive Income [Member]	Retained Earnings (Defecit) [Member]	Total [Member]
In Thousands
Balances at Dec. 31, 2010	'	$1,755	$714,869	($41,487)	$130,187	$264,581	$1,069,905
Net income (loss)	90,046	'	'	'	'	90,046	90,046
Hedge settlements reclassified into earnings from AOCI, net of income tax	'	'	'	'	58,125	'	58,125
Net change in derivative fair value, net of income tax	156,160	'	'	'	156,160	'	156,160
Foreign currency translation adjustment	-13,364	'	'	'	-13,364	'	-13,364
Issuance & vesting of stock compensation	'	-13	-20,849	-4,864	'	'	-15,998
Stock option exercises	'	2	1,297	'	'	'	1,299
Balances at Dec. 31, 2011	'	1,770	737,015	-46,351	214,858	354,627	1,261,919
Net income (loss)	-2,352,606	'	'	'	'	-2,352,606	-2,352,606
Hedge settlements reclassified into earnings from AOCI, net of income tax	'	'	'	'	128,161	'	128,161
Net change in derivative fair value, net of income tax	74,384	'	'	'	74,384	'	74,384
Foreign currency translation adjustment	412	'	'	'	412	'	412
Issuance & vesting of stock compensation	'	-19	-14,369	-3,144	'	'	-11,244
Stock option exercises	'	1	10	'	'	'	11
Balances at Dec. 31, 2012	'	1,790	751,394	-49,495	161,493	-1,997,979	-1,132,797
Net income (loss)	161,618	'	'	'	'	161,618	161,618
Hedge settlements reclassified into earnings from AOCI, net of income tax	'	'	'	'	46,931	'	46,931
Net change in derivative fair value, net of income tax	0	'	'	'	'	'	'
Foreign currency translation adjustment	-4,681	'	'	'	-4,681	'	-4,681
Issuance & vesting of stock compensation	'	-50	-18,698	-1,927	'	'	-16,821
Balances at Dec. 31, 2013	'	$1,840	$770,092	($51,422)	$109,881	($1,836,361)	($1,005,970)

Consolidated_Statements_Of_Equ1

Consolidated Statements Of Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Stockholders' Equity [Abstract]	'	'	'
Income tax effect related to hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income	$21,581	$66,417	$26,679
Income tax effect related to net change in derivative fair value	$0	$36,206	$73,339

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities:	'	'	'
Net income (loss)	$161,618,000	($2,352,606,000)	$90,046,000
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Depletion, depreciation and accretion	62,612,000	163,624,000	225,763,000
Impairment expense	1,863,000	2,625,928,000	107,059,000
Write-off of MLP related fees and expenses	0	7,505,000	0
Gain on Tokyo Gas Transaction	'	'	0
Crestwood earn-out	'	'	0
Deferred income tax expense (benefit)	-21,581,000	289,981,000	-64,492,000
Non-cash (gain) loss from hedging and derivative activities	3,904,000	57,826,000	-51,780,000
Stock-based compensation	17,979,000	22,246,000	20,862,000
Non-cash interest expense	26,920,000	9,854,000	16,510,000
Fortune Creek accretion	19,245,000	19,472,000	0
Gain on disposition of BBEP units	0	0	-217,893,000
Loss from BBEP in excess of cash distributions	0	0	28,269,000
Other	6,783,000	1,037,000	1,311,000
Changes in assets and liabilities	'	'	'
Accounts receivable	-3,994,000	30,950,000	-31,803,000
Prepaid expenses and other assets	322,000	-4,435,000	-6,017,000
Accounts payable	-7,133,000	-8,895,000	-11,434,000
Income taxes payable	7,828,000	1,183,000	-4,803,000
Accrued and other liabilities	-31,900,000	-14,884,000	22,471,000
Net cash provided by (used in) operating activities	-51,700,000	227,727,000	253,053,000
Investing activities:	'	'	'
Capital expenditures	-101,288,000	-485,479,000	-690,607,000
Proceeds from Asset Sales	'	41,097,000	'
Proceeds from sale of BBEP units	0	0	272,965,000
Proceeds from sale of properties and equipment	7,171,000	72,725,000	4,163,000
Purchases of marketable securities	-213,738,000	0	0
Maturities and sales of marketable securities	47,603,000	0	0
Net cash provided by (used in) investing activities	246,044,000	-371,657,000	-413,479,000
Financing activities:	'	'	'
Issuance of debt	1,237,352,000	467,959,000	855,822,000
Repayments of debt	-1,308,382,000	-310,430,000	-843,108,000
Debt issuance costs paid	-26,296,000	-3,022,000	-12,506,000
Partnership funds received	0	0	122,913,000
Distribution of Fortune Creek Partnership funds	-14,965,000	-14,285,000	0
Proceeds from exercise of stock options	0	11,000	1,299,000
Purchase of treasury stock	-1,927,000	-3,144,000	-4,864,000
Net cash provided by (used in) financing activities	-114,218,000	137,089,000	119,556,000
Effect of exchange rate changes in cash	4,026,000	-1,354,000	-921,000
Net change in cash and cash equivalents	84,152,000	-8,195,000	-41,791,000
Cash and cash equivalents at beginning of period	4,951,000	13,146,000	54,937,000
Cash and cash equivalents at end of period	89,103,000	4,951,000	13,146,000
Synergy [Member]	'	'	'
Investing activities:	'	'	'
Proceeds from Asset Sales	42,297,000	0	0
Tokyo Gas [Member]	'	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Gain on Tokyo Gas Transaction	-339,328,000	0	0
Crestwood earn-out	-339,328,000	'	'
Investing activities:	'	'	'
Proceeds from Asset Sales	463,999,000	0	0
kwk_CrestwoodLP [Member]	'	'	'
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:	'	'	'
Crestwood earn-out	0	-41,097,000	0
Investing activities:	'	'	'
Proceeds from Asset Sales	$0	$41,097,000	$0

Nature_Of_Operations

Nature Of Operations	12 Months Ended
	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Nature Of Operations	'
	NATURE OF OPERATIONS
	We are an independent oil and gas company incorporated in the state of Delaware and headquartered in Fort Worth, Texas. We engage in the acquisition, exploration, development, production and sale of natural gas, NGLs and oil in North America. As of December 31, 2013, our significant oil and gas reserves and operations are located in:
	•	Texas
	•	Alberta
	•	British Columbia
	We have offices located in:
	•	Fort Worth, Texas
	•	Glen Rose, Texas
	•	Calgary, Alberta
	Our results of operations are largely dependent on the difference between the prices received for our natural gas, NGL and oil products and the cost to find, develop, produce and market such resources. Natural gas, NGL and oil prices are subject to fluctuations in response to changes in supply, market uncertainty and a variety of other factors beyond our control. These factors include worldwide political instability, quantities of natural gas in storage, foreign supply of natural gas and oil, the price of foreign imports, the level of consumer demand and the price of available alternative fuels. We actively manage a portion of the financial risk relating to natural gas, NGL and oil price volatility through derivatives.
	Due to the depressed price environment for natural gas, we incurred significant impairments in 2012 on our oil and gas assets and in turn, tax valuation allowances which contributed to the consolidated net loss for 2012. At December 31, 2013, we continue to have significant indebtedness, whose interest costs consume significant amounts of our operating cash flow. As more fully described in Note 11, at December 31, 2013 we did not meet an incurrence test in our indentures which is not an event of default, but as a result, we are limited in our ability to, among other things, incur additional debt. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default in our indentures. At December 31, 2013, there was $97.6 million available from the $350 million global borrowing base under the Combined Credit Agreements. The next semi-annual redetermination of the Combined Credit Agreement is scheduled for April 2014. We have made only preliminary strides in the April 2014 redetermination process and cannot yet determine what, if any, adjustment occurs to the borrowing base. We anticipate our 2014 capital program, contractual commitments and recurring operating needs will be funded by cash flow from operations or cash on hand and supplemented by proceeds from asset sales. While we believe we have sufficient liquidity even without completing the Southwestern Transaction (as described in Note 3) completing it will improve our expected liquidity.
	Given the capital intensive nature of our business, the amount of capital expenditures we deploy or do not deploy would have a significant impact on our EBITDA in 2015 and future periods. We project that we will comply with the financial maintenance covenants associated with our Combined Credit Agreements in 2014, however we do not expect to exceed the required levels by a significant margin, and we may have to reduce costs in response to commodity price changes or other factors should they arise. Further, in order to comply with the requirements under our debt agreements, including the financial maintenance covenants, we may need to alter our capital program, adjust our incentive awards and repay a portion of our senior indebtedness. Note 11 contains additional discussion of our covenant requirements. In addition, due to more stringent financial maintenance covenants that take effect in 2015, absent an improvement in natural gas and NGL prices, significant deleveraging from a strategic transaction, reduced interest costs on our debt through refinancing or significant reductions to our operating costs, we may not comply with our interest coverage requirement under our Combined Credit Agreements and expect that we would need to seek additional covenant relief under the Combined Credit Agreements. We can provide no assurance that we would be successful in obtaining waivers or amendments. We are currently pursuing a transaction involving our Horn River Asset. Any transaction involving our Horn River Asset is likely to result in cash proceeds to us and a reduction in our capital expenditures and liquidity requirements, however we may be unsuccessful in completing such transaction.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Significant Accounting Policies	'
	SIGNIFICANT ACCOUNTING POLICIES
	Basis of Presentation
	Our consolidated financial statements include our accounts and those of all of our majority-owned subsidiaries, companies over which we exercise control through majority voting rights or other means of control and variable interest entities of which we are the primary beneficiary. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. We account for our ownership in unincorporated partnerships and companies, including our prior interest in BBEP, under the equity method when we have significant influence over those entities, but because of terms of the ownership agreements, we do not meet the criteria for consolidation of the entities.
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable, but such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.
	Significant estimates underlying these financial statements include the estimated quantities of our proved reserves (including the associated future net cash flows from those proved reserves and costs to develop those reserves) used to compute depletion expense, the full cost ceiling limitation and estimates of current revenue. Other estimates that require assumptions concerning future events and substantial judgment include the estimated fair value of derivatives, asset retirement obligations and stock-based compensation. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and our ability to recover operating loss carry-forwards and assessment of uncertain tax positions.
	Cash Equivalents
	Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.
	Accounts Receivable
	We sell our production to various purchasers, each of which is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we rarely require collateral, we require appropriate credit ratings and, in some instances, obtain parental guarantees. Receivables are generally collected within 30 to 60 days. When collections of specific amounts due are no longer reasonably assured, we establish an allowance for doubtful accounts though we have not had a significant instance of nonpayment. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers individually accounted for 21% and 15% of cash collected for our production revenue. During 2011, two purchasers accounted for 15% and 11% of cash collected for our production revenue.
	Hedging and Derivatives
	We enter into derivatives to mitigate risk associated with the prices received from our natural gas, NGL and oil production. We may also utilize derivatives to hedge the risk associated with interest rates on our outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.
	Effective December 31, 2012, we discontinued the use of hedge accounting on all existing hedge contracts. Net deferred hedge gains deferred in AOCI associated with these contracts as of December 31, 2012 are reclassified to earnings during the same periods in which the hedged transactions are recognized in our earnings. Since then, we recognize changes in the fair values of derivative contracts as gains or losses in the earnings of the periods in which they occur.
	We enter into derivatives with counterparties who are our lenders at the inception of the derivative. Our credit facility provides for collateralization of amounts outstanding from our derivatives in addition to amounts outstanding under the facility. Additionally, default on any of our obligations under derivatives with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility. Our credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes credit risk into consideration, whether it be our counterparties’ or our own. Derivatives are classified as current or non-current derivative assets and liabilities, based on the expected timing of settlements.
	Investments in Equity Affiliates
	During December 2011, we liquidated our investment in BBEP which we had accounted for using the equity method. Prior to this liquidation, we reviewed our investment for impairment whenever events or circumstances indicated that the investment’s carrying amount may not be recoverable. We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. Consequently, our 2011 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011. Note 7 contains more information on our BBEP investment.
	Property, Plant, and Equipment
	We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in separate Canadian and U.S. cost centers. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals reduce the accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved reserves. We may, at our option, exclude costs associated with unevaluated properties from amounts subject to depletion.
	Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations (collectively, “the cost center ceiling”). The cost center ceiling equals the sum of (1) estimated future net revenue from proved reserves, discounted at 10% per annum, including the effects of derivatives that are accounted for as hedges of our oil and gas revenue, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability, unless in a valuation allowance, and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 8 to these financial statements contains further discussion of the ceiling test.
	Other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years. If indicators of impairment are identified, an undiscounted cash flow analysis is performed to determine if an impairment exists. If the undiscounted cash flow analysis indicates an impairment, a discounted cash flow analysis is performed and the asset is reduced to the indicated value.
	Inventory
	Inventories are primarily comprised of materials and parts including oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials, parts and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or fair value, on a first-in, first-out cost basis. Fair value represents net realizable value, which is the amount that we are allowed to bill to the joint accounts under joint operating agreements to which we are a party. Impairments for materials and supplies inventories are recorded as lease operating expense in the accompanying consolidated statements of operations.
	Asset Retirement Obligations
	We record the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted liability to its estimated settlement value.
	Revenue Recognition
	Revenue is recognized when title to the products transfers to the purchaser. We use the “sales method” to account for our production revenue, whereby we recognize revenue on all production sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2013 and 2012, our aggregate production imbalances were not material.
	Environmental Compliance and Remediation
	Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.
	Debt
	We record all debt instruments at face value. When an issuance of debt is made at other than par, a discount or premium is separately recorded. The discount or premium is amortized over the life of the debt using the effective interest method.
	Income Taxes
	Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must reflect tax rates expected to be in effect in years in which the temporary differences reverse. Canadian taxes are calculated at rates expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus not considered available for distribution to the parent company. It is not practicable to determine our unrecognized deferred tax liability for temporary differences related to investments in foreign subsidiaries that are essentially permanent in duration. Net operating loss carry-forwards and other deferred tax assets are reviewed annually for recoverability, and, if necessary, are recorded net of a valuation allowance. Note 13 contains additional discussion regarding income taxes.
	Stock-based Compensation
	We measure and recognize compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value at the time the awards are granted. Our board of directors may elect to issue awards payable in cash. For awards with service requirements, we recognize the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. For awards that vest only upon achievement of performance criteria, recognition is recorded only when achievement of the performance criteria is considered probable.
	Disclosure of Fair Value of Financial Instruments
	Our financial instruments include cash, commercial paper, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated as the present value of future cash flows discounted at rates consistent with comparable maturities and includes consideration of credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.
	Foreign Currency Translation
	Our Canadian subsidiary maintains its general ledger using the Canadian dollar. All balance sheet accounts of our Canadian operations are translated into U.S. dollars at the period end exchange rate and statement of income items are translated at the weighted average exchange rate for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated results of operations.
	Variable Interest Entities
	An entity is a variable interest entity (VIE) if it meets the following criteria: (1) the entity has equity that is insufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors that cannot make significant decisions about the entity’s operations or that do not absorb their proportionate share of the expected losses or receive the expected returns of the entity.
	VIEs require assessment of who the primary beneficiary is and whether the primary beneficiary should consolidate the VIE. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impacts the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. Application of the VIE consolidation requirements may require the exercise of significant judgment by management.
	In 2011, we began to include the financial position of Fortune Creek and the results of operations were included beginning with the period ended December 31, 2012 in our consolidated financial statements. The results from operations of Fortune Creek for 2011 were immaterial. Note 15 contains additional discussion regarding Fortune Creek.
	Earnings per Share
	We report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. Note 17 includes the calculation of earnings per share.
	Recently Issued Accounting Standards
	No pronouncements materially affecting our financial statements have been issued since the filing of our 2012 Annual Report on Form 10-K.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2013
Acquisitions And Divestitures [Abstract]	'
Acquisitions And Divestitures	'
	DIVESTITURES
	In March 2014, we executed an agreement with Southwestern Energy Company to sell a majority of our Niobrara Asset for cash proceeds of $90 million. The Southwestern Transaction is expected to close in May 2014.
	In October and November 2013, we executed two separate agreements involving our West Texas Asset, the largest of which is a joint venture with Eni whereby we will jointly evaluate, explore and develop approximately 52,500 gross acres currently held by us in Pecos County, Texas. Under the terms of the agreement, Eni will pay up to $52.0 million in three phases to earn a 50% interest in our acreage. Upon completion of the three phases, we will participate equally in all future revenue, operating costs and capital expenditures with Eni.
	In August 2013, we completed the sale of our Southern Alberta Basin Asset to Synergy with an effective date of January 1, 2013. The purchase price was $46.0 million, which was subject to customary purchase price adjustments, resulting in a final purchase price of $42.3 million. We determined that the Synergy Transaction did not represent a significant disposal of reserves, therefore our U.S. oil and gas properties were reduced by these proceeds and we did not recognize a gain.
	In April 2013, we sold an undivided 25% interest in our Barnett Shale Asset to TGBR for a purchase price of $485.0 million. The effective date of the transaction was September 1, 2012. The purchase price was subject to customary price adjustments, which resulted in a final purchase price of $464.0 million. We recognized a gain of $339.3 million before consideration of income taxes as a result of this transaction based on our determination that the Tokyo Gas Transaction represented a significant disposal of reserves. Our U.S. oil and gas properties were reduced by $110.7 million as a result of the Tokyo Gas Transaction.
	In December 2012, we entered into an agreement with SWEPI LP to jointly develop our oil and gas interests in the Niobrara formation of the Sand Wash Basin and to establish an Area of Mutual Interest (“AMI”) covering in excess of 850,000 acres. Each party assigned to the other a 50% working interest in the majority of its combined acreage so that each party owns a 50% interest in more than 320,000 acres and has the right to a 50% interest in any acquisition within the AMI. SWEPI paid us an equalization payment for 50% of the acreage contributed by us in excess of the acreage that SWEPI contributed. SWEPI is the operator of the majority of the jointly owned lands. Subsequently, these assets are being sold in the Southwestern Transaction described above.

Derivatives_And_Fair_Value_Mea

Derivatives And Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
Credit Risk Derivatives, at Fair Value, Net [Abstract]	'
Derivatives And Fair Value Measurements	'
	DERIVATIVES AND FAIR VALUE MEASUREMENTS
	The following table categorizes our commodity derivative instruments based upon the use of input levels:
		Asset Derivatives							Liability Derivatives
		As of December 31,							As of December 31,
		2013				2012			2013			2012
		(in thousands)							(in thousands)
	Level 2 inputs	$	107,395			$	207,042		$	3,448		$	959
	Level 3 inputs	23,485				11,595			—			16,526
	Total	$	130,880			$	218,637		$	3,448		$	17,485
	The fair value of “Level 2” derivative instruments included in these disclosures was estimated using prices quoted in active markets for the periods covered by the derivatives and the value reported by counterparties. The fair value of derivative instruments designated as “Level 3” was estimated using prices quoted in markets where there is insufficient market activity for consideration as “Level 2” instruments. Currently, only our natural gas derivatives with an original tenure of 10 years utilize “Level 3” inputs, primarily due to comparatively less market data available for the later portion of their term compared with our shorter term derivatives. The fair value of both the “Level 2” and the “Level 3” assets and liabilities are determined using a discounted cash flow model using the terms of the derivative instrument, market prices for the periods covered by the derivatives, and the credit adjusted risk-free interest rates. The “Level 3” unobservable inputs are the market prices for the estimated market values for the period from 2018 to 2021, as there is not an active market for that period of time. These unobservable inputs included within the fair value calculation range from $4.00 to $4.80 and are based upon prices quoted in active markets for the period of time available and applying the differential from this period of time to the market prices for the later years in the term.
	The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:
		As of December 31,
		2013				2012
		(In thousands)
	Balance at beginning of period	$	(4,931	)		$	150,989
	Total gains (losses) for the period:
	Unrealized gain on derivatives	40,398				19,451
	Transfers out of Level 3	—				(180,732		)
	Settlements in production revenue	—				(3,738		)
	Settlements in net derivative losses	(11,982		)		(25,203		)
	Unrealized gains reported in OCI	—				34,302
	Balance at end of period	$	23,485			$	(4,931	)
	Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	41,909			$	19,451
	In 2012, transfers from Level 3 to Level 2 represent our ten-year derivative instruments that were exchanged in January and February 2012 for derivative instruments with shorter durations and which were valued on the date of the transfer.
	Commodity Price Derivatives
	As of December 31, 2013, we had natural gas and NGL swaps as follows:
	Production		Daily Production
	Year		Volume
			Natural Gas		NGL		Natural Gas Basis Swaps
			MMcfd		MBbld		MMcfd
	2014 (1)		170		4		40
	2015		150		—		—
	2016-2021		40		—		—
	-1	Our 2014 NGL derivatives end in September. Our natural gas derivatives and AECO to NYMEX natural gas basis swaps are in place for the whole of 2014.
	Effective December 31, 2012, we discontinued the use of hedge accounting. Changes in value subsequent to this date are recognized in net derivative gains (losses) in the period in which they occur. The net deferred hedge gain that was included in AOCI as of December 31, 2012 is being released into revenue from natural gas, NGL and oil production during the following periods in which we expect the underlying production to occur:
		(In thousands)
	2014	$	37,084
	2015	33,191
	2016	13,476
	2017	12,531
	2018 and thereafter	$	41,443
		$	137,725
	Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings during the following twelve months would result in a gain of $25.0 million net of income taxes.
	Interest Rate Derivatives
	In 2010, we executed early settlements of our interest rate swaps that were designated as fair value hedges of our senior notes due 2015 and our senior subordinated notes. We received cash of $41.5 million in the settlements, including $10.7 million for interest previously accrued and earned. Upon the early settlements, we recorded the resulting gain as a fair value adjustment to our debt and began to recognize the deferred gain of $30.8 million as a reduction of interest expense over the lives of our senior notes due 2015 and our senior subordinated notes.
	In June 2013, we repurchased substantially all our senior notes due 2015 resulting in early recognition of the previously deferred gain of $8.3 million. During 2013 and 2012, we recognized $12.0 million and $5.1 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $4.8 million deferral of the 2010 early settlements from the senior subordinated notes interest rate swaps will continue to be recognized as a reduction of interest expense over the life of those instruments currently scheduled as follows:
		(In thousands)
	2014	2,039
	2015	2,194
	2016	569
		$	4,802
	Fair Value Disclosures
	The estimated fair value of all of our derivative instruments at December 31, 2013 and 2012 were as follows:
		Asset Derivatives								Liability Derivatives
		As of December 31,								As of December 31,
		2013				2012				2013			2012
		(In thousands)								(In thousands)
	Derivatives not designated as hedges:
	Commodity contracts reported in:
	Current derivative assets	$	60,063			$	113,367			$	2,540		$	—
	Noncurrent derivative assets	105,315				107,542				31,958			2,272
	Current derivative liabilities	—				—				3,125			—
	Noncurrent derivative liabilities	—				92				323			17,577
Total derivatives not designated as hedges	$	165,378			$	221,001			$	37,946		$	19,849
Derivative assets and liabilities shown in the table above are presented as gross assets and liabilities, without regard to master netting arrangements, which are considered in the presentation of derivative assets and liabilities in the accompanying consolidated balance sheets. The change in carrying value of our commodity price derivatives since December 31, 2012 principally resulted from the overall increase in market prices for natural gas relative to the prices in our open derivative instruments, offset by settlements during the period.
The changes in the carrying value of our derivatives accounted for as hedges for 2012 are presented below:
	For the Year Ended December 31, 2012
	Commodity Hedges
	(In thousands)
Derivative fair value at beginning of period	$	342,799
Settlements in production revenue	(176,084		)
Settlements in net derivative gains	(3,820		)
Ineffectiveness reported in net derivative gains	1,281
Unrealized gains reported in OCI	107,112
Derecognition of hedge	(271,288		)
Derivative fair value at end of period	$	—
Investments
We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. We classify our marketable securities within “Level 2.” These held-to-maturity marketable securities are included in Cash and Cash Equivalents if the maturities at the time we made the investment were three months or less. For maturities greater than three months but less than a year, the marketable securities are included in current Marketable Securities. We did not sell or transfer any of our marketable securities during 2013 and do not anticipate selling or transferring these investments before their maturity date. At December 31, 2013, we had the following marketable securities:
	Amortized Cost				Gross Unrealized Gains			Gross Unrealized Losses			Fair Market Value
	(In thousands)
Marketable securities (held-to-maturity)
Time deposits	$	29,419			$	—		$	(22	)	$	29,397
Commercial paper	136,924				27			(25		)	136,926
Marketable securities	$	166,343			$	27		$	(47	)	$	166,323
We had no marketable securities at December 31, 2012.
Financial instruments not carried at fair value
Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of December 31, 2013 and December 31, 2012 are included in Note 11.

Accounts_Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2013
Accounts Receivable, Net [Abstract]	'
Accounts Receivable	'
	ACCOUNTS RECEIVABLE
	Accounts receivable consisted of the following:
		As of December 31,
		2013			2012
		(In thousands)
	Accrued production revenue	$	34,785		$	49,762
	Joint interest billings	15,630			10,957
	Income taxes	7,931			—
	Canadian value added taxes	60			172
	NGL hedge settlement accrual	—			3,149
	Other	328			160
	Allowance for doubtful accounts	(89		)	(51		)
		$	58,645		$	64,149

Other_Current_Assets

Other Current Assets	12 Months Ended
	Dec. 31, 2013
Other Current Assets [Abstract]	'
Other Current Assets	'
	OTHER CURRENT ASSETS
	Other current assets consisted of the following:
		As of December 31,
		2013		2012
		(In thousands)
	Inventories	$	18,334	$	21,454
	Deposits	1,044		513
	Other prepaid expense	2,968		3,079
		$	22,346	$	25,046

Investment_In_BBEP

Investment In BBEP	12 Months Ended
	Dec. 31, 2013
Equity Method Investment, Summarized Financial Information [Abstract]	'
Investment In BBEP	'
	INVESTMENT IN BBEP
	Since December 31, 2011 we own no BBEP Units. We recognized gains of $217.9 million for the year ended December 31, 2011 as other income for the difference between our weighted average carrying value of $3.51 per BBEP Unit and the net sales proceeds.
	We accounted for our investment in BBEP Units using the equity method, utilizing a one-quarter lag from BBEP’s publicly available information. Summarized financial information for BBEP is as follows:
		For the Twelve
		Months Ended
		September 30, 2011
		(in thousands)
	Revenue (1)	$	425,386
	Operating expense	313,388
	Operating income	111,998
	Interest and other (2)	40,759
	Income tax (benefit) expense	1,070
	Noncontrolling interests	183
	Net income available to BBEP	$	69,986
	Net income available to common unitholders	$	69,986
	(1)	For the twelve months ended September 30, 2011, unrealized gains of $24.0 million on commodity derivatives were recognized.
	(2)	The twelve months ended September 30, 2011 included $3.3 million for unrealized gains on interest rate swaps.

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Property, Plant And Equipment	'
	PROPERTY, PLANT AND EQUIPMENT
	Property, plant and equipment consisted of the following:
		As of December 31,
		2013				2012
		(In thousands)
	Oil and gas properties
	Subject to depletion	$	5,687,557			$	5,770,913
	Unevaluated costs	221,605				307,267
	Accumulated depletion	(5,268,719		)		(5,297,220		)
	Net oil and gas properties	640,443				780,960
	Other property and equipment
	Pipelines and processing facilities	347,093				375,248
	General properties	72,125				75,147
	Accumulated depreciation	(198,856		)		(202,297		)
	Net other property and equipment	220,362				248,098
	Property, plant and equipment, net of accumulated depletion and depreciation	$	860,805			$	1,029,058
	Ceiling Test Analysis and Impairment
	The charges for impairment are summarized below:
				Pre-tax Charges for Impairment
		Segment		2013				2012				2011
				(in thousands)
	U.S.
	Oil and gas properties	Exploration and production		$	—			$	2,152,128			$	—
	Other property and equipment	Midstream		54				7,328				57,996
	Other property and equipment	Exploration and production		1,809				537				—
	Canada
	Oil and gas properties	Exploration and production		—				465,935				49,063
				$	1,863			$	2,625,928			$	107,059
	As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and gas properties in each of our cost centers. We did not recognize impairment in 2013 during our quarterly ceiling tests. We did recognize other property and equipment impairment charges in 2013 for surface land and pipeline in Texas.
	In 2012, we recognized impairment expense each quarter as the average of the first of month prices for the preceding 12 months declined each quarter. For our U.S. oil and gas properties, the Henry Hub price declined 33% from the price used at December 31, 2011 and the pricing used for NGLs declined 28% from the price used at December 31, 2011. For our Canadian oil and gas properties, the AECO price declined 36% from the price used at December 31, 2011. In 2012, the impairment on our oil and gas properties in both the U.S. and Canada was impacted by the exclusion of our derivatives from the ceiling test due to the discontinuance of hedge accounting. Other property and equipment impairment charges during 2012 were a result of reduced anticipated utilization of pipelines and facilities in Colorado and Texas and reduced use of a compressed natural gas facility in Texas.
	The charge for impairment of our oil and gas properties in Canada in 2011 was recognized as a result of a 12% decrease in AECO natural gas price utilized in our Canadian ceiling test from December 31, 2010 to March 31, 2011.
	We also recognized an impairment charge of $58.0 million in 2011 related to certain Barnett Shale midstream assets to reduce their carrying value to estimated fair value as a result of decreased development by us and others in response to decreased natural gas prices during the fourth quarter of 2011.
	Unevaluated Natural Gas and Oil Properties Not Subject to Depletion
	Under full cost accounting, we may exclude certain unevaluated property costs from the amortization base pending determination of whether proved reserves have been discovered or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2013 and 2012 and the year in which they were incurred follows:
		December 31, 2013 Costs Incurred During																December 31, 2012 Costs Incurred During
		2013				2012				2011				Prior		Total		2012		2011		2010		Prior		Total
		(In thousands)																(In thousands)
	U.S.
	Acquisition costs	$	—			$	3,013			$	13,484			$	—	$	16,497	$	6,844	$	42,339	$	1,447	$	32,429	$	83,059
	Exploration costs	14				364				—				—		378		2,676		207		—		—		2,883
	Capitalized interest	1,093				1,374				—				—		2,467		4,093		—		—		—		4,093
	Total U.S.	$	1,107			$	4,751			$	13,484			$	—	$	19,342	$	13,613	$	42,546	$	1,447	$	32,429	$	90,035
	Canada
	Acquisition costs	$	—			$	2,956			$	1,300			$	68,586	$	72,842	$	333	$	—	$	643	$	80,488	$	81,464
	Exploration costs	$	7,044			$	31,746			$	41,092			$	30,413	$	110,295	$	36,356	$	44,837	$	18,500	$	20,171	$	119,864
	Capitalized interest	$	3,947			$	2,724			$	3,522			$	8,933	$	19,126	$	2,796	$	3,614	$	2,830	$	6,664	$	15,904
	Total Canada	$	10,991			$	37,426			$	45,914			$	107,932	$	202,263	$	39,485	$	48,451	$	21,973	$	107,323	$	217,232
	Total	$	12,098			$	42,177			$	59,398			$	107,932	$	221,605	$	53,098	$	90,997	$	23,420	$	139,752	$	307,267
	The following table summarizes the regions where we have unevaluated property costs not subject to depletion.
		As of December 31,
		2013				2012
		(In thousands)
	Barnett Shale	$	—			$	40,716
	West Texas	19,343				49,318
	Horn River Basin	202,262				217,233
	Total	$	221,605			$	307,267
	Costs are transferred into the amortization base on an ongoing basis, as projects are evaluated and proved reserves established or impairment determined. Pending determination of proved reserves attributable to the above costs, we cannot assess the future impact on the amortization rate. Unevaluated acquisition costs in our Horn River Asset will require up to an estimated nine more years of exploration and development activity before evaluation is complete, which is covered by the remaining primary term of the underlying leases. Unevaluated acquisition costs in our West Texas Asset will require up to an estimated three more years of exploration and development activity before evaluation is complete, which is covered by the remaining primary term and the renewal term of the underlying leases.
	Other Matters
	Capitalized overhead costs that directly relate to exploration and development activities were $13.6 million, $16.8 million and $18.3 million for 2013, 2012 and 2011, respectively. For 2013, depletion per Mcfe was $0.51 and $0.14 for the U.S. and Canada, respectively. For 2012, depletion per Mcfe was $1.14 and $0.83 for the U.S. and Canada, respectively. For 2011, consolidated depletion per Mcfe was $1.35. Depreciation expense was $17.1 million, $18.6 million and $20.3 million for 2013, 2012 and 2011, respectively.

Other_Assets

Other Assets	12 Months Ended
	Dec. 31, 2013
Other Assets, Noncurrent Disclosure [Abstract]	'
Other Assets	'
	OTHER ASSETS
	Other assets consisted of the following:
		As of December 31,
		2013			2012
		(In thousands)
	Deferred financing costs	$	84,951		$	59,059
	Less accumulated amortization	(50,171		)	(27,335		)
	Net deferred financing costs	34,780			31,724
	Governmental and notes receivable	6,464			7,385
	Other	360			838
		$	41,604		$	39,947
	Costs related to the acquisition of debt are deferred and amortized over the term of the debt.

Accrued_Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2013
Accrued Liabilities [Abstract]	'
Accrued Liabilities	'
	ACCRUED LIABILITIES
	Accrued liabilities consisted of the following:
		As of December 31,
		2013		2012
		(In thousands)
	Interest payable	$	38,260	$	67,116
	Accrued operating expense	37,747		38,733
	Prepayments from partners	425		—
	Revenue payable	22,589		21,013
	Accrued state income and franchise taxes	1,080		1,183
	Accrued production and property taxes	870		609
	Environmental liabilities	36		122
	Accrued product purchases	270		336
	Current asset retirement obligations	433		577
	Other	1,140		971
		$	102,850	$	130,660

LongTerm_Debt

Long-Term Debt

12 Months Ended

Dec. 31, 2013

Long-term Debt, Other Disclosures [Abstract]

'

Long-Term Debt

'

LONG-TERM DEBT

Long-term debt consisted of the following:

As of December 31,

2013

2012

(In thousands)

Combined Credit Agreements

$

211,200

$

388,150

Second Lien Term Loan, net of unamortized discount of $17,428

607,572

—

Second Lien Notes due 2019, net of unamortized discount of $5,577

194,423

—

Senior notes due 2015, net of unamortized discount of $30 and $2,149

10,472

435,851

Senior notes due 2016, net of unamortized discount of $105 and $10,825

8,044

579,795

Senior notes due 2019, net of unamortized discount of $4,757 and $5,378

293,243

292,622

Senior notes due 2021, net of unamortized discount of $15,810

309,190

—

Senior subordinated notes due 2016

350,000

350,000

Total debt

1,984,144

2,046,418

Unamortized deferred gain—terminated interest rate swaps

4,802

16,788

Long-term debt

$

1,988,946

$

2,063,206

Maturities are as follows:

2014

2015

2016

2017

2018

Thereafter

(in thousands)

Combined Credit Agreements

—

—

211,200

—

—

—

Second Lien Term Loan

—

—

—

—

—

625,000

Second Lien Notes due 2019

—

—

—

—

—

200,000

Senior notes due 2015

—

10,502

—

—

—

—

Senior notes due 2016

—

—

8,149

—

—

—

Senior notes due 2019

—

—

—

—

—

298,000

Senior notes due 2021

—

—

—

—

—

325,000

Senior subordinated notes due 2016

—

—

350,000

—

—

—

Total Indebtedness

—

10,502

569,349

—

—

1,448,000

The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the earliest maturity of the 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding exceeds $100 million. The table above does not reflect these accelerated maturities. We believe we have and will have sufficient liquidity and capital resources to defer these springing maturities until at least the last half of 2015.

Combined Credit Agreements

The Combined Credit Agreements’ global borrowing base was $350 million and the global letter of credit capacity was $280 million as of December 31, 2013. At December 31, 2013, we had $97.6 million available under the Combined Credit Agreements, all of which could be used for letters of credit.

We amended our Combined Credit Agreements in 2013 for the following:

•

Reduce the global borrowing base to $350 million from $850 million, including the reduction due to the Tokyo Gas Transaction

•

Reduce the minimum required interest coverage ratio to the following:

Period

Interest Coverage Ratio

Period

Interest Coverage Ratio

Q4 2013

1.1

Q2 2015

1.15

Q1 2014

1.1

Q3 2015

1.15

Q2 2014

1.1

Q4 2015

1.2

Q3 2014

1.1

Q1 2016

1.5

Q4 2014

1.1

Q2 2016

2

Q1 2015

1.1

•

Permit up to $825 million of second lien debt

•

Permit redemption of junior debt with the proceeds from certain asset sales and permitted second lien debt, provided utilization under the global borrowing base after giving effect to such redemption is less than 75% and compliance with other customary conditions

•

Reduce the maximum senior secured debt leverage ratio to 2.0 and exclude permitted second lien debt from the senior secured debt definition

•

Increase the applicable margin by 0.75% for each type of loan and issued letters of credit

•

Increase the minimum mortgage properties requirement to 87.5% from 80% of proved hydrocarbon interests evaluated in the then most recent reserve report

•

Amend certain definitions which impact the financial covenant calculations.

The Amended and Restated U.S. Credit Facility also provides for the extension of swingline loans to Quicksilver. Borrowings under the Amended and Restated U.S. Credit Facility bear interest at a variable annual rate based on adjusted LIBOR or ABR plus, in each case, an applicable margin, provided that each swingline loan must be comprised entirely of ABR loans. Borrowings under the Amended and Restated Canadian Credit Facility may be made in U.S. dollars or Canadian dollars and bear interest at a variable annual rate based on Canadian prime loans, Canadian Deposit Offer Rate (“CDOR”) loans, U.S. prime loans or Eurodollar loans plus, in each case, an applicable margin. The applicable margin under both credit facilities adjusts as the utilization of the global borrowing base changes.

Our ability to remain in compliance with covenants in our Combined Credit Agreements may be affected by events beyond our control, including market prices for our products. Any future inability to comply with these covenants, unless waived or amended by the requisite lenders, could adversely affect our liquidity by rendering us unable to borrow further under our credit facilities and by accelerating the maturity of our indebtedness. Note 1 contains additional information regarding our ability to comply with our financial covenants.

Debt Refinancing

During 2013, we executed multiple debt transactions, including payment of $51.4 million of cancellation premiums and discounts and tender premiums, included in interest expense, which are more fully described below, to extend our debt maturities and reduce the weighted average interest costs. Deferred issuance costs related to the new debt were $23.4 million, and $4.1 million of incurred costs related to the repurchased debt were recognized as interest expense. Proceeds from the Second Lien Term Loan and the issuance of Second Lien Notes due 2019 and Senior Notes due 2021 were used to pay for validly tendered Senior Notes due 2015 and Senior Notes due 2016 and accrued interest thereon and transaction expenses, including a consent fee.

Second Lien Term Loan

In June 2013, we entered into a $625 million six-year Second Lien Term Loan which is a secured senior obligation of Quicksilver. The loans thereunder were made at 97% of par, which resulted in net proceeds of $606.3 million. The Second Lien Term Loan has a variable annual interest rate based on adjusted LIBOR (as defined in the Second Lien Term Loan, which is subject to a floor of 1.25%) plus an applicable margin of 5.75% or Alternate Base Rate (as defined in the Second Lien Term Loan, which is subject to a floor of 2.25%) plus an applicable margin of 4.75%.

Second Lien Notes due 2019

In June 2013, we issued $200 million of Second Lien Notes due 2019 which are secured senior obligations of Quicksilver. The notes were issued at 97% of par, which resulted in net proceeds of $194 million. The Second Lien Notes have a variable annual interest rate based on LIBOR (as defined in the indenture governing the Second Lien Notes due 2019, which is subject to a floor of 1.25%) plus an applicable margin of 5.75%. Interest is payable on the last day of each quarter.

Senior Notes Due 2015

In June 2008, we issued $475 million of senior notes due 2015, which are unsecured senior obligations of Quicksilver. The notes were issued at 98.66% of par. Interest at the rate of 8.25% is payable semiannually on February 1 and August 1.

In June 2013, we made a cash tender offer and consent solicitation for the Senior Notes due 2015 at a price of $1,027.90 plus interest of $32.08 per $1,000 outstanding. We accepted and paid for all validly tendered notes, representing $425.2 million of the then outstanding $438.0 million, which resulted in an aggregate payment of $450.7 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes. Subsequent to the June tender offer and consent solicitation, we have repurchased an additional $2.3 million aggregate principal amount of the Senior Notes due 2015.

Senior Notes Due 2016

In June 2009, we issued $600 million of senior notes due 2016, which are unsecured senior obligations of Quicksilver. The notes were issued at 96.72% of par, which resulted in proceeds of $580.3 million that were used to repay a portion of debt. Interest at the rate of 11.75% is payable semiannually on January 1 and July 1.

In June 2013, we made a cash tender offer and consent solicitation for the Senior Notes due 2016 at a price of $1,068 plus interest of $55.49 per $1,000 outstanding. We accepted and paid for all validly tendered notes, representing $582.5 million of the then outstanding $590.6 million, which resulted in an aggregate payment of $654.4 million for such repurchase. We also entered into a supplemental indenture to eliminate substantially all of the restrictive covenants and certain events of default with respect to such notes.

Senior Notes Due 2019

In August 2009, we issued $300 million of senior notes due 2019, which are unsecured senior obligations of Quicksilver. The notes were issued at 97.61% of par, which resulted in proceeds of $292.8 million that were used to repay a portion of our 2007 Senior Secured Credit Facility. Interest at the rate of 9.125% is payable semiannually on February 15 and August 15.

In June 2013, we announced a consent solicitation for the Senior Notes due 2019 and entered into supplemental indentures to permit the refinancing of the Senior Subordinated Notes due 2016 by incurring indebtedness that ranks equally in right of payment with the Senior Notes due 2019 provided such indebtedness has maturities longer than the Senior Notes due 2019, which resulted in the payment of an $11.5 million consent fee to the consenting holders of the Senior Notes due 2019.

Senior Notes due 2021

In June 2013, we issued $325 million of Senior Notes due 2021, which are unsecured senior obligations of Quicksilver. The notes were issued at 94.928% of par, which resulted in proceeds of $308.5 million. Interest at the rate of 11.00% is payable semiannually on January 1 and July 1.

Senior Subordinated Notes

In 2006, we issued $350 million of senior subordinated notes due 2016. The senior subordinated notes are unsecured senior subordinated obligations of Quicksilver. Interest at the rate of 7.125% is payable semiannually on April 1 and October 1.

Indenture Restrictions

We have an incurrence test under our indentures applicable to debt, restricted payments, mergers and consolidations and designation of unrestricted subsidiaries that requires EBITDA to exceed interest expense by 2.25 times. At December 31, 2013, we did not meet this test and, as a result, we are limited in our ability to, among other things, incur additional debt, except for specific baskets. We do retain, however, the ability to utilize the full borrowing capacity under our Combined Credit Agreements and to refinance existing debt. Not meeting this ratio does not represent an event of default under our debt. We cannot predict when or if we will meet the incurrence test.

We retained a portion of cash received from our 2013 asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from asset sales within one year. If certain capital spending and senior debt repayment thresholds are not met, we would be required to make an offer to repay our notes. We expect to meet the remaining obligation in our indentures through our planned capital program and investments during 2014, but may also repay a portion of our senior indebtedness.

Interest Expense

Interest expense was $251.8 million and $164.1 million, net of capitalized interest of $7.7 million and $18.4 million, for the years ended December 31, 2013 and 2012, respectively.

Summary of All Outstanding Debt

The following table summarizes certain significant aspects of our long-term debt outstanding at December 31, 2013:

Priority on Collateral and Structural Seniority (1)

Highest priority

Lowest priority

First Lien

Second Lien

Senior Unsecured

Senior Subordinated

Combined Credit

Second Lien Term Loan

Second Lien Notes due 2019

2015

2016

2019

2021

Senior

Agreements

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Subordinated Notes

Principal amount (2)

$350 million

$625 million

$200 million

$11 million

$8 million

$298 million

$325 million

$350 million

Scheduled maturity date (3)

September 6, 2016

June 21, 2019

June 21, 2019

August 1, 2015

January 1, 2016

August 15, 2019

July 1, 2021

April 1, 2016

Interest rate on outstanding borrowings at December 31, 2013 (4)

3.95%

7.00%

7.00%

8.25%

11.75%

9.13%

11.00%

7.12%

Base interest rate

LIBOR, ABR, CDOR

LIBOR floor of 1.25%; ABR floor of 2.25%

LIBOR floor of 1.25%

N/A

N/A

N/A

N/A

N/A

options (5)(6)

Financial covenants (7)

- Minimum current ratio of 1.0

N/A

N/A

N/A

N/A

N/A

N/A

N/A

- Minimum EBITDA to cash interest expense ratio of 1.10

- Maximum senior secured debt leverage ratio of 2.0

Significant restrictive covenants (7)

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

- Asset sales

- Asset sales

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

- Incurrence of liens

- Incurrence of liens and 1st lien cap

- Incurrence of liens and 1st lien cap

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Limitations on derivatives and investments

Optional redemption (7)

Any time

Any time, subject to re-pricing event

Any time, subject to re-pricing event

August 1,

July 1,

August 15,

July 1,

April 1,

June 21,

June 21,

2013: 101.938

2013: 105.875

2014: 104.563

2019: 102.000

2013: 101.188

2014: 102

2014: 102

2014: par

2014: 102.938

2015: 103.042

2020: par

2014: par

2015: 101

2015: 101

2015: par

2016: 101.521

2017: par

Make-whole redemption (7)

N/A

N/A

N/A

N/A

N/A

Callable prior to

Callable prior to

N/A

15-Aug-14

July 1, 2019 at

at make-whole

make-whole call price of

call price of

Treasury +50 bps

Treasury +50 bps

Change of control (7)

Event of default

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

principal plus

principal plus

principal plus

principal plus

principal plus

principal plus

principal plus

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

Equity clawback (7)

N/A

N/A

N/A

N/A

N/A

N/A

Redeemable until

N/A

1-Jul-16

at 111.00%, plus

accrued interest

for up to 35%

Estimated fair value (8)

$211.2 million

$625 million

$200 million

$10.6 million

$7.8 million

$298 million

$354.3 million

$341.3 million

-1

Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

-2

The principal amount for the Combined Credit Agreements represents the global borrowing base as of December 31, 2013.

-3

The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding is greater than $100 million.

-4

Represents the weighted average borrowing rate payable to lenders.

-5

Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario, (ii) an applicable margin between 1.75% and 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

-6

Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. We pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

-7

The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

-8

The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Asset Retirement Obligations	'
	ASSET RETIREMENT OBLIGATIONS
	The following table provides a reconciliation of the changes in the estimated asset retirement obligation from January 1, 2012 through December 31, 2013.
		As of December 31,
		2013			2012
		(In thousands)
	Beginning asset retirement obligations	$	116,526		$	85,822
	Additional liability incurred	3,922			4,072
	Change in estimates	7,582			21,080
	Accretion expense	5,109			4,122
	Asset retirement costs incurred	(1,560		)	(1,846		)
	Settlement of liability in excess of obligation recorded	742			2,229
	Disposition	(21,935		)	—
	Currency translation adjustment	(3,697		)	1,047
	Ending asset retirement obligations	106,689			116,526
	Less current portion	(433		)	(577		)
	Long-term asset retirement obligation	$	106,256		$	115,949

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
Components of Deferred Tax Assets and Liabilities [Abstract]	'
Income Taxes	'
	INCOME TAXES
	Significant components of our deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
		As of December 31,
		2013				2012
		(In thousands)
	Deferred tax assets:
	Property, plant and equipment	$	209,134			$	483,771
	Net operating loss carry-forwards	183,982				109,100
	Investment in Fortune Creek	3,763				3,763
	AMT tax credit	47,883				55,814
	Settlements of interest rate swaps	1,681				5,876
	Deferred compensation expense	11,711				11,141
	State	3,680				—
	Other	791				2,710
	Deferred tax assets	462,625				672,175
	Deferred tax liabilities:
	Net derivative gains	(44,039		)		(73,195		)
	Other	(991		)		—
	Deferred tax liabilities	(45,030		)		(73,195		)
	Net deferred tax asset (liability)	417,595				598,980
	Valuation allowance	(417,595		)		(598,980		)
	Total deferred tax asset (liability)	$	—			$	—
	Reflected in the consolidated balance sheets as:
	Current deferred income tax liability	$	—			$	—
	Non-current deferred income tax liability	—				—
		$	—			$	—
	The components of net income (loss) before income tax for 2013, 2012 and 2011 are as follows:
		2013				2012				2011
						(In thousands)
	U.S.	$	184,034			$	(2,142,730	)		$	146,090
	Canada	(7,866		)		(505,446		)		1,819
	Total	$	176,168			$	(2,648,176	)		$	147,909
	No rate changes occurred in any taxing jurisdiction for 2011 or 2012. For 2013 and beyond, we have utilized a rate of 25.2% in Canada and a federal rate of 35% and a state rate of 1% in the U.S. to value our deferred tax positions, with the U.S. federal and state future rates mirroring existing applicable rates.
	The components of income tax expense for 2013, 2012 and 2011 are as follows:
		2013				2012				2011
						(In thousands)
	Current state income tax expense (benefit)	$	900			$	1,752			$	(1,706	)
	Current U.S. federal income tax expense (benefit)	(7,931		)		—				(5,565		)
	Current Canadian income tax expense	—				—				642
	Total current income tax expense (benefit)	(7,031		)		1,752				(6,629		)
	Deferred U.S. federal income tax expense (benefit)	205,820				(763,639		)		58,890
	U.S. federal valuation allowance expense	(186,713		)		533,974				—
	Deferred state income tax expense (benefit)	(3,680		)		—				1,980
	State valuation allowance expense	3,680				—				—
	Deferred Canadian income tax expense (benefit)	827				(128,982		)		3,622
	Canadian valuation allowance expense	1,647				61,325				—
	Total deferred income tax expense (benefit)	21,581				(297,322		)		64,492
	Total income tax expense (benefit)	$	14,550			$	(295,570	)		$	57,863
	The following table reconciles the statutory federal income tax rate to the effective tax rate for 2013, 2012 and 2011:
		2013			2012			2011
	U.S. federal statutory tax rate	35	%		35	%		35	%
	Permanent differences	4.8	%		(0.06	)%		1.51	%
	State income taxes net of federal deduction	0.31	%		(0.04	)%		0.12	%
	Canadian income taxes	(0.26	)%		(1.93	)%		2.41	%
	Other	(0.15	)%		0.67	%		0.08	%
	Derivatives deferred in OCI	12.43	%		—	%		—	%
	Valuation allowance	(43.87	)%		(22.48	)%		—	%
	Effective income tax rate	8.26	%		11.16	%		39.12	%
	As of December 31, 2012, we had net operating tax loss carry-forwards for federal tax purposes of $340 million. During the year ended December 31, 2013, we generated additional net operating losses of $185 million. The total $525 million is included in deferred tax assets, and will expire between 2029 and 2033. The net operating loss carry-forwards can be used to offset future taxable income. As of December 31, 2013, we have $48 million of alternative minimum tax credit carry-forwards to offset any future alternative minimum tax payments, which have no expiration.
	The deferred tax expense in 2013 is principally composed of the reversal in 2013 of deferred tax liabilities related to hedging in other comprehensive income that had previously reduced the valuation allowance necessary. During 2013, we reduced the U.S. federal deferred tax asset and corresponding valuation allowance by $187 million primarily due to the recognition of a deferred tax liability related to the Tokyo Gas Transaction. We also established a U.S. state valuation allowance of $3.7 million. The Canadian valuation allowance increased by $1.6 million primarily due to permanent items related to nondeductible expenses. Additionally, our basis in the Fortune Creek Partnership exceeds book basis by $29 million. We expect to realize the deferred tax asset related to this balance only through the partnership’s sale at which time the transaction will be treated as a capital transaction under Canadian tax law, taxed at the Canadian statutory rate of 12.5% for capital gains. We believe that it is more likely than not that we will be unable to realize the benefit of this deferred tax asset. Accordingly in 2011, we recorded a full valuation allowance of $3.7 million for this item.
	We file or have filed income tax returns in U.S. federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. We currently have no open audits. Tax years after December 31, 2009 remain subject to audit by the IRS.
	The following schedule reconciles the total amounts of unrecognized tax benefits for 2012:
		As of
December 31,
	2013			2012
	(In thousands)
Beginning unrecognized tax benefits	$	—		$	9,219
Changes	—			(9,219		)
Ending unrecognized tax benefits	$	—		$	—
Tax benefits of $9.2 million were recognized during the quarter ended September 30, 2012 as the statute of limitations related to uncertain tax positions expired.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2013
Loss Contingency [Abstract]	'
Commitments And Contingencies	'
	COMMITMENTS AND CONTINGENCIES
	Contractual Obligations
	Information regarding our contractual obligations, at December 31, 2013, is set forth in the following table:
		GPT		Drilling Rig		Operating		Purchase
		Contracts (1)		Contracts (2)		Leases (3)		Obligations (4)
		(In thousands)
	2014	$	86,628	$	4,240	$	3,912	$	3,071
	2015	85,043		—		3,994		220
	2016	81,803		—		4,123		—
	2017	78,326		—		4,070		—
	2018	65,860		—		4,043		—
	Thereafter	140,624		—		12,996		—
	Total	$	538,284	$	4,240	$	33,138	$	3,291
	(1)	Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts.
	(2)	We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contract requires payment of a specified day rate of $20,000 for the entire lease term regardless of our utilization of the drilling rigs.
	(3)	We lease office buildings and other property under operating leases. Rent expense for operating leases with terms exceeding one month was $3.6 million in 2013, $4.2 million in 2012 and $4.8 million in 2011. Minimum payments have not been reduced by minimum sublease rentals of $2.2 million due in the future under noncancelable subleases.
	(4)	At December 31, 2013, we were under contract to purchase goods and services for use in field and gas plant operations.
	Commitments and Contingencies
	In July 2013, in light of the Canadian Governor in Council's failure to approve NGTL's construction of the Komie North Project, NGTL terminated the Project and Expenditure Authorization (PEA), which authorized NGTL to construct the Komie North Project and the related meter station. The PEA necessitated the construction of a treatment facility and required financial guarantees to cover NGTL's costs for the Komie North Project. We recognized $12.8 million in related actual costs incurred by NGTL, which is reflected in other income (expense) in our consolidated financial statements. We paid NGTL in August 2013 after which the related letter of credit was terminated. With the termination of the PEA described above, our agreement to deliver gas to the Komie North Project has also terminated. We maintain our ability to sell gas at the Station 2 and AECO hubs, as our current production is served by existing treating facilities and pipelines.
	At December 31, 2013, we had $6.6 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $41.2 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.
	As a result of our partial working interest sale to Eni in 2009, we entered into a joint development agreement with Eni. The joint development agreement includes a schedule of wells that we agreed to drill and complete with participation by Eni during the development period. In connection with the scheduled drilling of these wells, we committed to drill and complete a minimum number of lateral feet each year and Eni agreed to pay us a turnkey drilling and completion cost per linear foot attributable to Eni. At December 31, 2013 we mutually agreed to end the turnkey drilling and completion provisions within the joint development agreement and both parties are responsible for their respective working interest percentage for drilling and completing activity on joint development wells.
	In July 2011, we received a subpoena duces tecum from the SEC requesting certain documents. The SEC has informed us that their investigation arose out of press releases in 2011 questioning the projected decline curves and economics of shale gas wells. In June 2012, we received an additional request from the SEC for certain information regarding our assessment for impairment of unevaluated properties and plans for development of unevaluated properties. We provided responsive information and in February 2013 we met with the SEC.
	In December 2012, Vantage Fort Worth Energy LLC (“Plaintiff”) served a lawsuit against us and others in the 352nd Judicial District Court of Texas in Tarrant County asserting claims for trespass to try title, suit to quiet title, trespass and conversion. On May 8, 2013, all parties to the suit entered into a settlement agreement, effective April 1, 2013, whereby we assigned to Plaintiff various property and equipment and Plaintiff agreed to non-suit all of the Defendants in the matter. The court entered its Order of Dismissal with prejudice on May 13, 2013. We recognized an expense of $3.3 million in connection with this settlement.
	We are subject to various proceedings and claims that arise in the ordinary course of business. While many of these matters involve inherent uncertainty, we believe, individually or in the aggregate, such matters will not have a material adverse impact on our financial position, results of operations or cash flows. Because of the uncertainty, our assessment may change in the future. If an unfavorable final outcome were to become probable or occur, it may have a material impact on our financial position, results of operations or cash flows for the period in which the effect becomes reasonably estimable.
	Environmental Compliance
	Our operations are subject to stringent, complex and changing laws and regulations pertaining to health, safety and the environment. As an owner, lessor or operator of our facilities, we are subject to laws and regulations at the federal, state, provincial and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities incorporates compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2013, we had recorded less than $0.1 million for liabilities for environmental matters.

Fortune_Creek

Fortune Creek	12 Months Ended
	Dec. 31, 2013
Equity Method Investments and Joint Ventures [Abstract]	'
Fortune Creek	'
	FORTUNE CREEK
	In December 2011, we entered into an agreement with KKR to form Fortune Creek to construct and operate midstream assets for natural gas produced by us and others primarily in British Columbia. The partnership established an area of mutual interest for the midstream business covering approximately 30 million potential acres which includes transportation and processing infrastructure and agreements.
	In forming Fortune Creek, our Canadian subsidiary contributed an existing 20-mile, 20-inch gathering line and its related compression facilities and committed to minimum gross capital expenditures of $300 million for drilling and completion activities in our Horn River Asset between 2012 and 2014. In March 2014, we agreed with KKR to an amendment to extend the ending date to the earlier of June 30, 2016 or 12 months following consummation of a transaction involving a material portion of our Horn River Asset and to broaden allowable spending to include acquisitions of producing properties that utilize partnership assets. We have incurred $180 million as of December 31, 2013. The costs to be incurred under the spending requirement generally reflect the gross capital expenditures of all working interests in the well for wells in which we have a working interest regardless of our working interest percentage; therefore, following a transaction involving our Horn River Asset, we may not have to fully fund the remaining obligation. To the extent these minimum capital expenditure commitments are not met, we will incur a cash penalty in an amount equal to the shortfall, which will be applied against the gathering agreement requirement. As part of the amendment, we contributed C$28 million to Fortune Creek which was subsequently distributed to KKR and was applied against the gathering agreement requirement. The effect of this contribution was to reduce the balance of the partnership liability and to reduce the gathering rate that burdens our Horn River Asset production by $0.13 per Mcf until at least 2016.
	We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed $125 million cash in exchange for a 50% interest in Fortune Creek. Our Canadian subsidiary has responsibility for the day-to-day operations of Fortune Creek.
	The firm gathering agreement with Fortune Creek is guaranteed by us. With the amendment, signed in March 2014, KKR is no longer required to fund the capital for construction of a proposed gas treatment facility, but at its option may provide funding for any facility to be constructed by the Partnership, including the proposed gas treatment facility. If our subsidiary does not meet its obligations under the gathering agreement, KKR has the right to liquidate the partnership and consequently we have recorded the funds contributed by KKR as a liability in our consolidated financial statements. We recognize accretion expense to reflect the rate of return earned by KKR via its investment. Fortune Creek has made cash distributions to KKR, which are reported as cash used in financing activities, since May 2012.
	Based on an analysis of the partners’ equity at risk, we have determined the partnership to be a VIE. Further, based on our ability to direct the activities surrounding the production of natural gas and our direct management of the operations of the Fortune Creek facilities, we have determined we are the primary beneficiary and, therefore, we consolidate Fortune Creek.
	Note 18 contains financial information for Fortune Creek in our condensed consolidating financial statements.

Quicksilver_Stockholders_Equit

Quicksilver Stockholders' Equity	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'
Quicksilver Stockholders' Equity	'
	QUICKSILVER STOCKHOLDERS’ EQUITY
	Common Stock, Preferred Stock and Treasury Stock
	We are authorized to issue 400 million shares of common stock with a $0.01 par value per share and 10 million shares of preferred stock with a $0.01 par value per share. At December 31, 2013, we had 177.3 million shares of common stock outstanding.
	The following table shows common share and treasury share activity since January 1, 2011:
		Common			Treasury
		Shares Issued			Shares Held
	Balance at January 1, 2011	175,524,816			5,050,450
	Stock options exercised	209,221			—
	Restricted stock activity	1,246,446			329,252
	Balance at December 31, 2011	176,980,483			5,379,702
	Stock options exercised	1,572			—
	Restricted stock activity	2,033,063			541,400
	Balance at December 31, 2012	179,015,118			5,921,102
	Stock options exercised	—			—
	Restricted stock activity	4,979,761			777,538
	Balance at December 31, 2013	183,994,879			6,698,640
	Quicksilver Stockholder Rights Plan
	In 2003, our Board of Directors declared a dividend distribution of one preferred share purchase right for each share of common stock then outstanding. Pursuant to the amendments entered into on March 8, 2013, each right, when it becomes exercisable, entitles stockholders to buy one one thousandth of a share of Quicksilver’s Series A Junior Participating Preferred Stock at an exercise price of $10, subject to customary anti-dilution adjustments.
	The rights will be exercisable only if such a person or group acquires 15% or more of our common stock or announces a tender offer the consummation of which would result in ownership by such a person or group (an “Acquiring Person”) of 15% or more of our common stock. This 15% threshold does not apply to certain members of the Darden family and affiliated entities (the "Darden Entities"), which collectively owned, directly or indirectly, approximately 30% of our common stock at February 28, 2014, so long as the Darden Entities do not acquire beneficial ownership of additional shares of our common stock, subject to certain exceptions and subject to the Darden Entities, collectively, being able to acquire additional shares of common stock to maintain the Darden Entities' collective percentage ownership in us.
	If an Acquiring Person acquires 15% or more of our outstanding common stock (or any Darden Entity exceeds the thresholds applicable to the Darden Entities), each right (other than the rights of the Acquiring Person, including, if applicable, the Darden Entities) will entitle its holder to purchase, at the right's then-current exercise price, a number of our common shares having a market value of twice such price. If we are acquired in a merger or other business combination transaction after an Acquiring Person has acquired 15% or more of our outstanding common stock (or any Darden Entity has exceeded the thresholds applicable to the Darden Entities), each right (other than the rights of the Acquiring Person, including, if applicable, the Darden Entities) will entitle its holder to purchase, at the right's then-current exercise price, a number of the acquiring company's common shares having a market value of twice such price.
	Prior to the acquisition by an Acquiring Person of beneficial ownership of 15% or more of our common stock (or any Darden Entity exceeds the thresholds applicable to the Darden Entities), the rights are redeemable for $0.01 per right at the option of our Board of Directors.
	The rights plan will expire by its terms on March 11, 2016.
	Stock-Based Compensation
	2006 Equity Plan
	In 2006, our Board of Directors and our stockholders approved the 2006 Equity Plan, under which 14 million shares of common stock were reserved for issuance as grants of stock options, appreciation rights, restricted shares, restricted stock units, performances shares, performance units and senior executive plan bonuses. In May 2009, our stockholders approved an amendment to the 2006 Equity Plan, which increased the number of shares available for issuance after such date to 15 million. On May 15, 2013, our stockholders approved an amendment to the 2006 Equity Plan, which increased the shares available for issuance under the plan by 12 million shares. Our executive officers, other employees, consultants and non-employee directors are eligible to participate in the 2006 Equity Plan. Options reflect an exercise price of no less than the fair market value on the date of grant and have a term that expires ten years from the date of grant. At December 31, 2013 and 2012, 15.4 million shares and 9.7 million shares, respectively, were available for issuance under the 2006 Equity Plan.
	Stock Options
	The following summarizes the values from and assumptions for the Black-Scholes option pricing model:
		2013		2012		2011
	Weighted average grant date fair value	$1.05		$4.21		$9.16
	Weighted average risk-free interest rate	1.31%		1.14%		2.38%
	Expected life	4.9 years		6.0 years		6.0 years
	Weighted average volatility	68.97%		68.20%		66.77%
	Expected dividends	—		—		—
	The following table summarizes our stock option activity for 2013:
		Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
							(In years)		(In thousands)
	Outstanding at January 1, 2013	4,979,980			$	10.23
	Granted	2,037,467			1.95
	Exercised	—			—
	Canceled	(85,004	)		6.63
	Expired	(160,865	)		8.86
	Outstanding at December 31, 2013	6,771,578			$	7.82	6.4		$	—
	Exercisable at December 31, 2013	4,576,677			$	9.3	5.3		$	—
	We estimate that a total of 6.3 million stock options will become vested including those options already exercisable. The unexercised options have a weighted average exercise price of $8.24 and a weighted average remaining contractual life of 6.2 years.
	As of December 31, 2013 the unrecognized compensation cost related to outstanding unvested options was $2.1 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $3.9 million, $7.4 million and $7.0 million was recognized for 2013, 2012 and 2011, respectively. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2013 and 2012 was $1.3 million and $2.4 million, respectively. The total intrinsic value of options exercised during 2012 and 2011 was $0.1 million and $1.2 million, respectively. No options were exercised in 2013.
	Restricted Stock and Stock Units
	The following table summarizes our restricted stock and stock unit activity for 2013:
		Payable in shares					Payable in cash
		Shares			Weighted		Shares			Weighted
					Average					Average
					Grant Date					Grant Date
					Fair Value					Fair Value
	Outstanding at January 1, 2013	3,099,135			$	8.48	678,217			$	7.71
	Granted	6,511,441			2.76		1,483,306			2.81
	Vested	(2,524,332	)		6.69		(284,406	)		8.51
	Canceled	(1,418,154	)		3.68		(304,776	)		3.86
	Outstanding at December 31, 2013	5,668,090			$	3.9	1,572,341			$	3.69
	As of December 31, 2013, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $13.3 million, which is expected to be recognized through December 2016. Grants of restricted stock and RSUs during 2013 had an estimated grant date fair value of $22.1 million. The fair value of RSUs to be settled in cash was $4.8 million and $1.9 million during 2013 and 2012, respectively. For 2013, 2012 and 2011, compensation expense related to restricted stock and RSUs of $16.8 million, $15.7 million and $13.9 million, respectively, was recognized. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense was $5.2 million during each of 2013 and 2012. The total fair value of shares vested during 2013, 2012 and 2011 was $7.1 million, $16.3 million and $13.6 million, respectively.
	In 2013, we recognized $2.4 million in stock-based compensation to correct for assumptions on forfeitures and vesting for retirement eligible and imminently retirement eligible individuals, which pertain to periods before 2013.
	Accumulated Other Comprehensive Income
	At December 31, 2013, AOCI included $94.5 million, net of tax, and $15.4 million for derivatives and foreign currency translation, respectively. At December 31, 2012, AOCI included $141.4 million, net of tax, and $20.1 million for derivatives and foreign currency translation, respectively.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Earnings Per Share	'
	EARNINGS PER SHARE
	The following is a reconciliation of the numerator and denominator used for the computation of basic and diluted net income per common share.
		Years Ended December 31,
		2013			2012			2011
		(In thousands, except per share data)
	Net income (loss) attributable to Quicksilver	$	161,618		$	(2,352,606	)	$	90,046
	Basic income allocable to participating securities (1)	(4,252		)	—			(1,106		)
	Income (loss) available to shareholders	$	157,366		$	(2,352,606	)	$	88,940
	Weighted average common shares – basic	171,518			170,106			168,993
	Effect of dilutive securities (2)
	Share-based compensation awards	141			—			742
	Weighted average common shares — diluted	171,659			170,106			169,735
	Earnings (loss) per common share — basic	$	0.92		$	(13.83	)	$	0.53
	Earnings (loss) per common share — diluted	$	0.92		$	(13.83	)	$	0.52
	(1)	Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.
	(2)	For 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
Condensed Consolidating Financial Information	'
	CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	The following tables provide information about the entities that guarantee our senior notes and senior subordinated notes. The guarantees are full and unconditional and joint and several.
	Under SEC rules, we are required to present financial information segregated between our guarantor and non-guarantor subsidiaries. The indentures under both our senior notes and our senior subordinated notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries and further specify supplemental information that is not required under GAAP. The following table illustrates our subsidiaries and their status pursuant to the senior notes due 2015, senior notes due 2016, senior notes due 2019, senior notes due 2021 and the senior subordinated notes:
	Guarantor Subsidiaries -		Non-Guarantor Subsidiaries
	Restricted		Restricted		Unrestricted
	Cowtown Pipeline Funding, Inc.		Quicksilver Resources Canada Inc.		Makarios Resources International Holdings LLC (2)
	Cowtown Pipeline Management, Inc.		Cowtown Drilling Inc. (1)		1622834 Alberta Inc. (2)
	Cowtown Pipeline L.P.		Quicksilver Resources Partners Operating Ltd. (2)		Makarios Midstream Inc. (2)
	Cowtown Gas Processing L.P.		0942065 B.C. Ltd. (3)		Makarios Resources International Inc. (2)
	Barnett Shale Operating LLC (2)		0942069 B.C Ltd. (3)		Quicksilver Production Partners GP LLC (2)
	QPP Parent LLC (3)				Quicksilver Production Partners LP (2)
	QPP Holdings LLC (3)
	Silver Stream Pipeline Company LLC (3)
	-1	This entity was inactive for the three-year period ended December 31, 2013.
	(2)	These entities were created in 2011.
	(3)	These entities were created in 2012.
	We own 100% of each of the restricted subsidiaries.
	Quicksilver and the restricted subsidiaries conduct all of our exploration and production activities, and the unrestricted subsidiaries primarily conduct midstream operations. Neither the restricted non-guarantor subsidiaries nor the unrestricted non-guarantor subsidiaries guarantee the obligations under the senior notes or the senior subordinated notes.
	However, the restricted non-guarantor subsidiaries, like the restricted guarantor subsidiaries, are limited in their activity by the covenants in the indentures for such matters as:
	•	incurring additional indebtedness;
	•	paying dividends;
	•	selling assets;
	•	making investments; and
	•	making restricted payments.
	Subject to restrictions set forth in the indentures, we may in the future designate one or more additional subsidiaries as unrestricted.
	The following tables present financial information about Quicksilver and our restricted subsidiaries for the annual periods covered by the consolidated financial statements. Under the indenture, Fortune Creek is not considered to be a subsidiary and therefore it is presented separately from the other subsidiaries for these purposes.
	Condensed Consolidating Balance Sheets
		31-Dec-13
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	ASSETS
	Current assets	$	349,586			$	10,735		$	53,034		$	(19,642	)	$	393,713		$	909		$	1,110		$	(1,772	)	$	393,960
	Property and equipment	455,822				15,486			307,865			—			779,173			—			81,632			—			860,805
	Investment in subsidiaries (equity method)	(217,852		)		—			(33,840		)	217,852			(33,840		)	(33,840		)	—			67,680			—
	Other assets	472,792				—			32,892			(390,723		)	114,961			—			—			—			114,961
	Total assets	$	1,060,348			$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742		$	65,908		$	1,369,726
	LIABILITIES AND EQUITY
	Current liabilities	$	124,275			$	12,210		$	17,167		$	(19,642	)	$	134,010		$	888		$	1,671		$	(1,772	)	$	134,797
	Long-term liabilities	1,942,043				19,242			542,659			(390,723		)	2,113,221			—			1,546			126,132			2,240,899
	Quicksilver stockholders’ equity	(1,005,970		)		(5,231		)	(199,875		)	217,852			(993,224		)	(33,819		)	79,525			(58,452		)	(1,005,970		)
	Total liabilities and equity	$	1,060,348			$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742		$	65,908		$	1,369,726
		31-Dec-12
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	ASSETS
	Current assets	$	261,130			$	105,695		$	76,088		$	(222,586	)	$	220,327		$	13,250		$	391		$	(26,455	)	$	207,513
	Property and equipment	621,073				20,007			296,462			—			937,542			—			91,516			—			1,029,058
	Investment in subsidiaries (equity method)	(191,725		)		—			(42,883		)	191,725			(42,883		)	(42,905		)	—			85,788			—
	Other assets	346,972				—			41,865			(243,620		)	145,217			—			—			—			145,217
	Total assets	$	1,037,450			$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907		$	59,333		$	1,381,788
	LIABILITIES AND EQUITY
	Current liabilities	$	255,678			$	112,133		$	33,475		$	(222,586	)	$	178,700		$	13,230		$	2,316		$	(26,455	)	$	167,791
	Long-term liabilities	1,914,568				19,242			524,107			(243,620		)	2,214,297			—			1,585			130,912			2,346,794
	Quicksilver stockholders’ equity	(1,132,796		)		(5,673		)	(186,050		)	191,725			(1,132,794		)	(42,885		)	88,006			(45,124		)	(1,132,797		)
	Total liabilities and equity	$	1,037,450			$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907		$	59,333		$	1,381,788
	Condensed Consolidating Statements of Income
		For the Year Ended December 31, 2013
	Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
	Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
														Subsidiaries												Consolidated
	(In thousands)
Revenue	$	416,516			$	788		$	144,258		$	—		$	561,562		$	—		$	22,364		$	(22,364	)	$	561,562
Operating expenses	329,975				346			118,481			—			448,802			—			9,808			(22,364		)	436,246
Tokyo Gas Transaction gain	339,328				—			—			—			339,328			—			—			—			339,328
Equity in net earnings of subsidiaries	(9,896		)		—			(6,682		)	9,896			(6,682		)	12,563			—			(5,881		)	—
Operating income (loss)	415,973				442			19,095			9,896			445,406			12,563			12,556			(5,881		)	464,644
Fortune Creek accretion	—				—			—			—			—			—			—			(19,245		)	(19,245		)
Interest expense and other	(242,279		)		—			(26,959		)	—			(269,238		)	—			7			—			(269,231		)
Income tax expense	(12,076		)		—			(2,474		)	—			(14,550		)	—			—			—			(14,550		)
Net income (loss)	$	161,618			$	442		$	(10,338	)	$	9,896		$	161,618		$	12,563		$	12,563		$	(25,126	)	$	161,618
Other comprehensive loss	(40,166		)		—			(11,446		)	—			(51,612		)	—			—			—			(51,612		)
Equity in OCI of subsidiaries	(11,446		)		—			—			11,446			—			—			—			—			—
Comprehensive income (loss)	$	110,006			$	442		$	(21,784	)	$	21,342		$	110,006		$	12,563		$	12,563		$	(25,126	)	$	110,006
	For the Year Ended December 31, 2012
	Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
	Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
														Subsidiaries												Consolidated
	(In thousands)
Revenue	$	611,477			$	4,574		$	95,887		$	(2,900	)	$	709,038		$	—		$	14,639		$	(14,639	)	$	709,038
Operating expenses	2,643,690				4,109			577,696			(2,900		)	3,222,595			—			7,940			(14,639		)	3,215,896
Crestwood earn-out	41,097				—			—			—			41,097			—			—			—			41,097
Equity in net earnings of subsidiaries	(437,510		)		—			(12,747		)	437,510			(12,747		)	6,726			—			6,021			—
Operating income (loss)	(2,428,626		)		465			(494,556		)	437,510			(2,485,207		)	6,726			6,699			6,021			(2,465,761		)
Fortune Creek accretion	—				—			—			—			—			—			—			(19,472		)	(19,472		)
Interest expense and other	(152,077		)		—			(10,914		)	—			(162,991		)	21			27			—			(162,943		)
Income tax (expense) benefit	228,097				(163		)	67,658			—			295,592			—			—			(22		)	295,570
Net income (loss)	$	(2,352,606	)		$	302		$	(437,812	)	$	437,510		$	(2,352,606	)	$	6,747		$	6,726		$	(13,473	)	$	(2,352,606	)
Other comprehensive income (loss)	(57,273		)		—			3,908			—			(53,365		)	—			—			—			(53,365		)
Equity in OCI of subsidiaries	3,908				—			—			(3,908		)	—			—			—			—			—
Comprehensive income (loss)	$	(2,405,971	)		$	302		$	(433,904	)	$	433,602		$	(2,405,971	)	$	6,747		$	6,726		$	(13,473	)	$	(2,405,971	)
	For the Year Ended December 31, 2011
	Quicksilver				Restricted			Restricted			Consolidating			Quicksilver
	Resources Inc.				Guarantor			Non-Guarantor			Eliminations			Resources Inc.
					Subsidiaries			Subsidiaries						Consolidated
	(In thousands)
Revenue	$	778,741			$	4,573		$	163,864		$	(3,555	)	$	943,623
Operating expenses	603,582				64,476			156,516			(3,555		)	821,019
Equity in net earnings of subsidiaries	(40,725		)		—			—			40,725			—
Operating income (loss)	134,434				(59,903		)	7,348			40,725			122,604
Income from earnings of BBEP	(8,439		)		—			—			—			(8,439		)
Interest expense and other	39,252				18			(5,526		)	—			33,744
Income tax (expense) benefit	(75,201		)		20,960			(3,622		)	—			(57,863		)
Net income (loss)	$	90,046			$	(38,925	)	$	(1,800	)	$	40,725		$	90,046
Other comprehensive income (loss)	67,493				—			17,178			(17,178		)	67,493
Equity in OCI of subsidiaries	17,178				—			—			—			17,178
Comprehensive income (loss)	$	174,717			$	(38,925	)	$	15,378		$	23,547		$	174,717
Condensed Consolidating Statements of Cash Flows
	For the Year Ended December 31, 2013
	Quicksilver				Restricted			Restricted			Quicksilver			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
	Resources Inc.				Guarantor			Non-Guarantor			and Restricted									Resources Inc.
					Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
	(In thousands)
Net cash flow provided by (used in) operating activities	$	(78,565	)		$	—		$	16,456		$	(62,109	)	$	—		$	10,409		$	(51,700	)
Capital expenditures	(67,263		)		—			(33,520		)	(100,783		)	—			(505		)	(101,288		)
Proceeds from Tokyo Gas Transaction	463,999				—			—			463,999			—			—			463,999
Proceeds from Synergy Transaction	42,297				—			—			42,297			—			—			42,297
Proceeds from sale of properties and equipment	7,128				—			43			7,171			—			—			7,171
Purchase of marketable securities	(213,738		)		—			—			(213,738		)	—			—			(213,738		)
Maturities and sales of marketable securities	47,603				—			—			47,603			—			—			47,603
Net cash flow provided by (used in) investing activities	280,026				—			(33,477		)	246,549			—			(505		)	246,044
Issuance of debt	1,215,266				—			22,086			1,237,352			—			—			1,237,352
Repayments of debt	(1,157,969		)		—			(150,413		)	(1,308,382		)	—			—			(1,308,382		)
Debt issuance costs	(26,296		)		—			—			(26,296		)	—			—			(26,296		)
Intercompany Note	(147,103		)		—			147,103			—			—			—			—
Distribution of Fortune Creek Partnership funds	—				—			—			—			—			(14,965		)	(14,965		)
Purchase of treasury stock	(1,927		)		—			—			(1,927		)	—			—			(1,927		)
Net cash flow provided by (used in) financing activities	(118,029		)		—			18,776			(99,253		)	—			(14,965		)	(114,218		)
Effect of exchange rates on cash	—				—			(1,755		)	(1,755		)	—			5,781			4,026
Net increase in cash and equivalents	83,432				—			—			83,432			—			720			84,152
Cash and equivalents at beginning of period	4,618				—			—			4,618			—			333			4,951
Cash and equivalents at end of period	$	88,050			$	—		$	—		$	88,050		$	—		$	1,053		$	89,103
	For the Year Ended December 31, 2012
	Quicksilver				Restricted			Restricted			Quicksilver			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
	Resources Inc.				Guarantor			Non-Guarantor			and Restricted									Resources Inc.
					Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	163,353			$	656		$	49,271		$	213,280		$	—		$	14,447		$	227,727
Capital expenditures	(231,934		)		(656		)	(242,158		)	(474,748		)	—			(10,731		)	(485,479		)
Proceeds from Crestwood earn-out	41,097				—			—			41,097			—			—			41,097
Proceeds from sale of properties and equipment	72,362				—			363			72,725			—			—			72,725
Net cash flow used in investing activities	(118,475		)		(656		)	(241,795		)	(360,926		)	—			(10,731		)	(371,657		)
Issuance of debt	228,500				—			239,459			467,959			—			—			467,959
Repayments of debt	(264,018		)		—			(46,412		)	(310,430		)	—			—			(310,430		)
Debt issuance costs	(1,972		)		—			(1,050		)	(3,022		)	—			—			(3,022		)
Distribution of Fortune Creek Partnership funds	—				—			—			—			—			(14,285		)	(14,285		)
Proceeds from exercise of stock options	11				—			—			11			—			—			11
Purchase of treasury stock	(3,144		)		—			—			(3,144		)	—			—			(3,144		)
Net cash flow provided by (used in) financing activities	(40,623		)		—			191,997			151,374			—			(14,285		)	137,089
Effect of exchange rates on cash	—				—			527			527			—			(1,881		)	(1,354		)
Net increase (decrease) in cash and equivalents	4,255				—			—			4,255			—			(12,450		)	(8,195		)
Cash and equivalents at beginning of period	363				—			—			363			—			12,783			13,146
Cash and equivalents at end of period	$	4,618			$	—		$	—		$	4,618		$	—		$	333		$	4,951
	For the Year Ended December 31, 2011
	Quicksilver				Restricted			Restricted			Quicksilver			Fortune			Consolidating			Quicksilver
	Resources Inc.				Guarantor			Non-Guarantor			and Restricted			Creek			Eliminations			Resources Inc.
					Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
	(In thousands)
Net cash flow provided by operating activities	$	202,043			$	2,225		$	48,785		$	253,053		$	—		$	—		$	253,053
Capital expenditures	(518,454		)		(2,225		)	(169,928		)	(690,607		)	—			—			(690,607		)
Proceeds from sale of BBEP units	272,965				—			—			272,965			—			—			272,965
Investment in Fortune Creek	—				—			(12,783		)	(12,783		)	—			12,783			—
Proceeds from sale of properties and equipment	2,959				—			1,204			4,163			—			—			4,163
Net cash flow provided by (used in) investing activities	(242,530		)		(2,225		)	(181,507		)	(426,262		)	—			12,783			(413,479		)
Issuance of debt	587,500				—			268,322			855,822			—			—			855,822
Repayments of debt	(588,862		)		—			(254,246		)	(843,108		)	—			—			(843,108		)
Debt issuance costs	(9,160		)		—			(3,346		)	(12,506		)	—			—			(12,506		)
Proceeds from exercise of stock options	1,299				—			—			1,299			—			—			1,299
Partnership funds received	—				—			—			—			135,696			(12,783		)	122,913
Creation of partnership liability	—				—			122,913			122,913			(122,913		)	—			—
Purchase of treasury stock	(4,864		)		—			—			(4,864		)	—			—			(4,864		)
Net cash flow provided by (used in) financing activities	(14,087		)		—			133,643			119,556			12,783			(12,783		)	119,556
Effect of exchange rates on cash	—				—			(921		)	(921		)	—			—			(921		)
Net increase (decrease) in cash and equivalents	(54,574		)		—			—			(54,574		)	12,783			—			(41,791		)
Cash and equivalents at beginning of period	54,937				—			—			54,937			—			—			54,937
Cash and equivalents at end of period	$	363			$	—		$	—		$	363		$	12,783		$	—		$	13,146

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	SEGMENT INFORMATION
	We operate in two geographic segments, the U.S. and Canada, where we are engaged in the exploration and production segment of the oil and gas industry. Additionally, we operate a significantly smaller midstream segment in the U.S. and Canada, where we provide natural gas gathering and processing services, primarily to our U.S. and Canadian exploration and production segments. Following the formation of our partnership with KKR, beginning in January 2012, we have additional midstream operations in Canada through Fortune Creek. Revenue earned by Fortune Creek for the gathering and processing of our gas is eliminated on a consolidated basis as is the GPT recognized by our producing properties. Based on the immateriality of our midstream segment, we have combined our U.S. and Canadian midstream information. We evaluate performance based on operating income and property and equipment costs incurred.
		Exploration & Production						Midstream									Quicksilver
		U.S.			Canada						Corporate			Elimination			Consolidated
		(In thousands)
	2013
	Revenue	$	416,462		$	141,870		$	25,594		$	—		$	(22,364	)	$	561,562
	DD&A	37,540			17,508			5,249			2,315			—			62,612
	Impairment expense	1,809			—			54			—			—			1,863
	Operating income (loss)	476,610			32,648			13,008			(57,622		)	—			464,644
	Property and equipment costs incurred	64,976			16,838			7,055			9,792			—			98,661
	2012
	Revenue	$	598,892		$	105,949		$	21,735		$	—		$	(17,538	)	$	709,038
	DD&A	123,370			32,686			5,182			2,386			—			163,624
	Impairment expense	2,152,665			465,935			7,328			—			—			2,625,928
	Operating income (loss)	(1,921,073		)	(474,768		)	8,163			(78,083		)	—			(2,465,761		)
	Property and equipment costs incurred	189,997			174,867			18,742			6,850			—			390,456
	2011
	Revenue	$	806,657		$	135,948		$	4,573		$	—		$	(3,555	)	$	943,623
	DD&A	171,438			47,116			4,889			2,320			—			225,763
	Impairment expense	—			49,063			57,996			—			—			107,059
	Operating income (loss)	251,495			12,914			(59,903		)	(81,902		)	—			122,604
	Property and equipment costs incurred	487,145			131,699			64,119			11,516			—			694,479
	Property, plant and equipment—net
	31-Dec-13	$	451,840		$	306,423		$	97,118		$	5,424		$	—		$	860,805
	31-Dec-12	614,071			294,921			111,523			8,543			—			1,029,058
	Total assets
	31-Dec-13	$	895,388		$	359,951		$	108,963		$	5,424		$	—		$	1,369,726
	31-Dec-12	784,104			371,532			217,609			8,543			—			1,381,788

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	SUPPLEMENTAL CASH FLOW INFORMATION
	Cash paid (received) for interest and income taxes is as follows:
		Years Ended December 31,
		2013		2012			2011
		(In thousands)
	Interest, net of capitalized interest	$	254,901	$	154,663		$	170,814
	Income taxes	833		(20,682		)	(4,249		)
	Other significant non-cash transactions are as follows:
		Years Ended December 31,
		2013		2012			2011
		(In thousands)
	Working capital related to capital expenditures	$	10,324	$	10,939		$	107,586
	Note receivable received for sale of land and building	—		—			5,300

Employee_Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2013
General Discussion of Pension and Other Postretirement Benefits [Abstract]	'
Employee Benefits	'
		EMPLOYEE BENEFITS
	Quicksilver has a 401(k) retirement plan available to all U.S. full time employees who are at least 21 years of age. We make matching contributions and a fixed annual contribution and have the ability to make discretionary contributions to the plan. Expense associated with company contributions was $1.8 million, $2.3 million and $2.3 million for 2013, 2012 and 2011, respectively.
	We have a retirement plan available to all Canadian employees. The plan provides for a match of employees’ contributions by us and a fixed annual contribution. Expense associated with company contributions for 2013, 2012 and 2011 was $0.7 million, $0.7 million and $0.8 million, respectively.
	We maintain a self-funded health benefit plan that covers all eligible U.S. employees. The plan has been reinsured on an individual claim and total group claim basis. We have an individual stop loss of $125,000. For 2013, 2012 and 2011 we recognized expense of $4.0 million, $5.0 million and $4.8 million, respectively, for this plan.

Transactions_With_Related_Part

Transactions With Related Parties	12 Months Ended
	Dec. 31, 2013
Related Party Transactions [Abstract]	'
Transactions With Related Parties	'
	TRANSACTIONS WITH RELATED PARTIES
	As of February 28, 2014, members of the Darden family and entities controlled by them beneficially own approximately 30% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors, and Thomas Darden is a director, of Quicksilver.
	During 2013, we paid $0.2 million in commission to an entity controlled by members of the Darden family in connection with the sublease of a portion of our office space. Additionally, we paid $0.1 million in 2012 and $0.2 million in 2011 for rent and property management services on buildings owned by entities controlled by members of the Darden family. Rental rates were determined based on comparable rates charged by third parties. In December 2011, we purchased a manufacturing facility from an entity controlled by members of the Darden family for $1.1 million. We previously leased this facility from the seller for the manufacture of oil and gas equipment.
	During 2013, 2012 and 2011, we paid $0.3 million, $0.5 million and $0.9 million for use of an airplane owned by an entity controlled by members of the Darden family. Usage rates were determined based upon comparable rates charged by third parties.
	Payments received from Mercury, a company owned by members of the Darden family, for sublease rentals, employee insurance coverage and administrative services were $0.1 million in each of 2013, 2012 and 2011.
	In May 2013, we entered into an agreement with Thomas F. Darden with respect to Mr. Darden’s retirement and Mr. Darden’s provision of consulting services following his retirement. Effective May 15, 2013, Mr. Darden retired from his executive position and continued to serve as a non-officer employee through December 31, 2013. Mr. Darden continues to serve as a member of the Board of Directors as Chairman Emeritus. In recognition of his contributions to the Tokyo Gas Transaction, Mr. Darden received a cash bonus of $1.1 million paid in two equal installments in May 2013 and August 2013, and a stock option grant with an aggregate grant date fair value of $1.1 million granted in May 2013. Both the cash bonus and the stock option grant are included in the Tokyo Gas Transaction gain on our consolidated financial statements. In connection with his retirement, he received full vesting of his outstanding unvested equity awards (242,724 shares of restricted stock and 304,407 options); reimbursement of legal fees in connection with the agreement, up to $40,000; and payment of accrued and unused vacation and estimated COBRA premiums. Mr. Darden is engaged as a consultant for the three-year period following his retirement as an employee and receives a monthly consulting fee of $45,000. In addition, while a consultant, Mr. Darden is entitled to an office allowance of $12,500 per month, and additional reimbursements, with respect to certain business expenses. In addition, Mr. Darden is eligible to receive bonuses of up to $2.5 million in the aggregate under certain circumstances in connection with certain possible future strategic transactions occurring on or before December 31, 2016.

Supplemental_Selected_Quarterl

Supplemental Selected Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Supplemental Selected Quarterly Financial Data	'
	SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
	The following table presents selected quarterly financial data derived from our consolidated financial statements. This summary should be read in conjunction with our consolidated financial statements and related notes also contained in this Item 8 to our Annual Report on Form 10-K.
		Quarter Ended
		March 31			June 30			September 30			December 31
		(In thousands, except per share data)
	2013 (1) (2) (3)
	Operating revenue	$	118,703		$	175,497		$	153,116		$	114,246
	Operating income (loss)	(3,874		)	394,894			60,049			13,575
	Net income (loss)	(59,707		)	242,523			10,577			(31,775		)
	Basic net earnings per share	$	(0.35	)	$	1.37		$	0.06		$	(0.18	)
	Diluted net earnings per share	(0.35		)	1.37			0.06			(0.18		)
	2012 (4) (5) (6) (7)
	Operating revenue	$	172,866		$	194,018		$	118,188		$	223,966
	Operating loss	(267,985		)	(1,153,012		)	(576,551		)	(468,213		)
	Net loss	(211,565		)	(802,022		)	(790,520		)	(548,499		)
	Basic net earnings per share	$	(1.24	)	$	(4.72	)	$	(4.65	)	$	(3.22	)
	Diluted net earnings per share	(1.24		)	(4.72		)	(4.65		)	(3.22		)
	(1)	Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.
	(2)	Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR.
	(3)	Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.
	(4)	Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.
	(5)	Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.
	(6)	Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of $359.9 million.
	(7)	Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited) (Notes)	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Supplemental Oil and Gas Information (Unaudited)	'
	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Proved oil and gas reserves estimates for our properties in the U.S. and Canada were prepared by independent petroleum engineers from Schlumberger Technology Corporation and LaRoche Petroleum Consultants, Ltd., respectively. The reserve reports were prepared in accordance with guidelines established by the SEC. Natural gas, NGL and oil prices used in the 2013, 2012 and 2011 reserve reports are the unweighted average of the preceding 12-month first-day-of-the-month prices as of the date of the reserve reports. For all years, operating costs, production and ad valorem taxes and future development costs were based on year-end costs with no escalation.
	There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting the future rates of production and timing of development expenditures. The following reserve data represent estimates only and should not be construed as being exact. Moreover, the present values should not be construed as the current market value of our natural gas, NGL and oil reserves or the costs that would be incurred to obtain equivalent reserves.
	The changes in our proved reserves for the three years ended December 31, 2013 were as follows:
		Natural Gas (MMcf)									NGL (MBbl)						Oil (MBbl)
		U.S.			Canada			Total			U.S.		Canada		Total		U.S.		Canada	Total
	December 31, 2010	1,941,723			265,888			2,207,611			112,444		12		112,456		3,308		—	3,308
	Revisions (3)	(172,643	)		15,066			(157,577	)		(8,519	)	1		(8,518	)	(43	)	—	(43	)
	Extensions and discoveries (2)	155,662			76,067			231,729			2,652		—		2,652		43		—	43
	Production	(95,838	)		(26,390	)		(122,228	)		(4,432	)	(2	)	(4,434	)	(273	)	—	(273	)
	31-Dec-11	1,828,904			330,631			2,159,535			102,145		11		102,156		3,035		—	3,035
	Revisions (3)	(910,386	)		(33,945	)		(944,331	)		(45,379	)	1		(45,378	)	(479	)	—	(479	)
	Extensions and discoveries (2)	25,858			9			25,867			3,518		—		3,518		345		—	345
	Sales in place (1)	(20,616	)		—			(20,616	)		(42	)	—		(42	)	(85	)	—	(85	)
	Production	(75,712	)		(29,912	)		(105,624	)		(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)
	31-Dec-12	848,048			266,783			1,114,831			56,173		10		56,183		2,529		—	2,529
	Revisions (3)	234,835			28,648			263,483			750		—		750		62		—	62
	Extensions and discoveries (2)	50,992			9,697			60,689			—		—		—		—		—	—
	Sales in place (4)	(257,741	)		—			(257,741	)		(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)
	Production	(51,684	)		(39,372	)		(91,056	)		(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)
	31-Dec-13	824,450			265,756			1,090,206			39,734		9		39,743		199		—	199
	Proved developed reserves
	31-Dec-11	1,244,187			299,371			1,543,558			60,902		11		60,913		2,545		—	2,545
	31-Dec-12	725,361			266,783			992,144			47,284		10		47,294		2,416		—	2,416
	31-Dec-13	702,147			260,159			962,306			34,603		9		34,612		139		—	139
	Proved undeveloped reserves
	31-Dec-11	584,717			31,260			615,977			41,243		—		41,243		490		—	490
	31-Dec-12	122,687			—			122,687			8,890		—		8,890		113		—	113
	31-Dec-13	122,303			5,896			128,199			5,131		—		5,131		60		—	60
	(1)	Sales of reserves in place during 2012 relate to our agreement to allow an outside working interest owner to fund the completion costs for twelve wells in our Barnett Shale Asset for which they received a preferential right to reserves. It also includes a minimal sale of reserves in our Niobrara Asset to SWEPI.
	(2)	Extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for:
	•	2013 are attributable to our Barnett Shale Asset;
	•	2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed); and
	•	2011 are 100% attributable to our Barnett Shale Asset (of which 11% were proved developed).
	Canadian extensions and discoveries for:
	•	2013 and 2012 are attributable to our Horseshoe Canyon Asset; and
	•	2011 are 97% attributable to our Horn River Asset and 3% are attributable to our Horseshoe Canyon Asset.
	(3)	Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in economic factors of 419,972 MMcfe, (590,064) MMcfe and (54,539) MMcfe in 2013, 2012 and 2011, respectively, and changes in non-economic factors of (151,615) MMcfe, (629,407) MMcfe and (154,405) MMcfe in 2013, 2012 and 2011, respectively, including:
	•	Removal of proved undeveloped reserves that had not been developed within five years: (76) Bcfe and (250) Bcfe in 2013 and 2012, respectively;
	•	changes in performance related to offsetting activities, higher pipeline pressures and other factors: (74) Bcfe and (291) Bcfe in 2013 and 2012, respectively and
	•	revision of type curve of non producing wells based on comparison to producing analogs: (88) Bcfe in 2012.
	(4)	Sales of reserves in place during 2013 relate to the Tokyo Gas Transaction (337 Bcfe) and the Synergy Transaction (15 Bcfe).
	The carrying value of our oil and gas assets as of December 31, 2013, 2012 and 2011 were as follows:
		U.S.				Canada				Consolidated
		(In thousands)
	2013
	Proved properties	$	4,645,777			$	1,041,780			$	5,687,557
	Unevaluated properties	19,343				202,262				221,605
	Accumulated DD&A	(4,268,387		)		(1,000,332		)		(5,268,719		)
	Net capitalized costs	$	396,733			$	243,710			$	640,443
	2012
	Proved properties	$	4,681,860			$	1,089,053			$	5,770,913
	Unevaluated properties	90,035				217,232				307,267
	Accumulated DD&A	(4,233,391		)		(1,063,829		)		(5,297,220		)
	Net capitalized costs	$	538,504			$	242,456			$	780,960
	2011
	Proved properties	$	4,380,745			$	928,585			$	5,309,330
	Unevaluated properties	252,737				180,604				433,341
	Accumulated DD&A	(1,965,258		)		(550,937		)		(2,516,195		)
	Net capitalized costs	$	2,668,224			$	558,252			$	3,226,476
	Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2013, were as follows:
		U.S.				Canada				Consolidated
		(In thousands)
2013
Proved acreage	$	—			$	—			$	—
Unproved acreage	15,843				6,305				22,148
Development costs	49,299				17,422				66,721
Exploration costs	—				—				—
Total	$	65,142			$	23,727			$	88,869
2012
Proved acreage	$	—			$	—			$	—
Unproved acreage	23,711				5,612				29,323
Development costs	131,926				178,808				310,734
Exploration costs	35,244				8,304				43,548
Total	$	190,881			$	192,724			$	383,605
2011
Proved acreage	$	—			$	—			$	—
Unproved acreage	145,099				—				145,099
Development costs	304,373				90,361				394,734
Exploration costs	37,673				41,338				79,011
Total	$	487,145			$	131,699			$	618,844
Consolidated results of operations, without giving consideration to any tax valuation allowance, from our producing activities for each of the three years ended December 31, 2013, are set forth below:
	U.S.				Canada				Consolidated
	(In thousands)
2013
Natural gas, NGL and oil revenue	$	331,964			$	131,527			$	463,491
Operating expense	167,425				80,475				247,900
Depletion expense	34,995				5,362				40,357
	129,544				45,690				175,234
Income tax expense	45,340				11,514				56,854
Results from producing activities	$	84,204			$	34,176			$	118,380
2012
Natural gas, NGL and oil revenue	$	538,902			$	92,045			$	630,947
Operating expense	226,542				60,501				287,043
Depletion expense	116,005				24,897				140,902
Impairment expense	2,152,128				465,935				2,618,063
	(1,955,773		)		(459,288		)		(2,415,061		)
Income tax benefit	(684,521		)		(114,822		)		(799,343		)
Results from producing activities	$	(1,271,252	)		$	(344,466	)		$	(1,615,718	)
2011
Natural gas, NGL and oil revenue	$	673,041			$	127,502			$	800,543
Operating expense	267,890				54,770				322,660
Depletion expense	164,493				38,228				202,721
Impairment expense	—				49,063				49,063
	240,658				(14,559		)		226,099
Income tax expense (benefit)	84,230				(4,222		)		80,008
Results from producing activities	$	156,428			$	(10,337	)		$	146,091
The Standardized Measure of Discounted Future Net Cash Flows and Changes Therein Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport to present the fair market value of our natural gas and oil properties. An estimate of such value should consider, among other factors, anticipated future prices of natural gas and oil, the probability of recoveries in excess of existing proved reserves, the value of probable reserves and acreage prospects, estimated future capital and operating costs and perhaps different discount rates. It should be noted that estimates of reserve quantities, especially from new discoveries, are inherently imprecise and subject to substantial revision.
Under the Standardized Measure, future cash inflows for 2013 were estimated by applying the unweighted average of the preceding 12-month first-day-of-the-month prices, adjusted for contracts with price floors but excluding hedges, and unescalated year-end costs to the estimated future production of the year-end reserves. These prices have varied widely and have a significant impact on both the quantities and value of the proved reserves as reduced prices cause wells to reach the end of their economic life much sooner and also make certain proved undeveloped locations uneconomical, both of which reduce reserves. The following representative prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:
	At December 31,
	2013				2012				2011
Natural gas – Henry Hub, per MMBtu	$	3.67			$	2.76			$	4.12
Natural gas – AECO, per MMBtu	2.9				2.35				3.65
Oil – WTI Cushing, per Bbl	97.18				94.71				95.71
The reference price used for our NGLs was based on WTI Cushing, adjusted for local differentials, gravity and BTU.
Future cash inflows were reduced by estimated future production and development costs based on year-end costs to determine pre-tax cash inflows. Future income taxes were computed by applying the statutory tax rate to the excess of pre-tax cash inflows over our tax basis in the associated proved natural gas and oil properties. Tax credits and net operating loss carry-forwards were also considered in the future income tax calculation. Future net cash inflows after income taxes were discounted using a 10% annual discount rate to arrive at the Standardized Measure.
The Standardized Measure at December 31, 2013, 2012 and 2011 was as follows:
	U.S.				Canada				Total
					(In thousands)
31-Dec-13
Future revenue	$	3,825,944			$	656,984			$	4,482,928
Future production costs	(2,022,977		)		(385,776		)		(2,408,753		)
Future development costs	(212,280		)		(79,525		)		(291,805		)
Future income taxes	(134,418		)		59,294				(75,124		)
Future net cash flows	1,456,269				250,977				1,707,246
10% discount	(801,116		)		(83,082		)		(884,198		)
Standardized measure of discounted future cash flows relating to proved reserves	$	655,153			$	167,895			$	823,048
31-Dec-12
Future revenue	$	3,980,643			$	472,539			$	4,453,182
Future production costs	(2,552,863		)		(324,424		)		(2,877,287		)
Future development costs	(239,532		)		(56,354		)		(295,886		)
Future income taxes	81,847				80,206				162,053
Future net cash flows	1,270,095				171,967				1,442,062
10% discount	(667,738		)		(59,204		)		(726,942		)
Standardized measure of discounted future cash flows relating to proved reserves	$	602,357			$	112,763			$	715,120
31-Dec-11
Future revenue	$	11,647,002			$	1,055,711			$	12,702,713
Future production costs	(5,496,246		)		(463,852		)		(5,960,098		)
Future development costs	(1,125,641		)		(146,658		)		(1,272,299		)
Future income taxes	(1,229,968		)		(44,183		)		(1,274,151		)
Future net cash flows	3,795,147				401,018				4,196,165
10% discount	(2,286,449		)		(174,863		)		(2,461,312		)
Standardized measure of discounted future cash flows relating to proved reserves	$	1,508,698			$	226,155			$	1,734,853
The standardized measure was calculated without giving consideration to any tax valuation allowance.
The primary changes in the Standardized Measure for 2013, 2012 and 2011 were as follows:
	Years Ended December 31,
	2013				2012				2011
					(In thousands)
Sales of oil and gas net of production costs	$	(147,402	)		$	(149,326	)		$	(477,883	)
Net changes in economic factors	326,698				(1,362,793		)		32,175
Extensions and discoveries	43,328				27,003				251,635
Development costs incurred	2,302				172,563				233,294
Changes in estimated future development costs	20,766				620,127				(60,642		)
Purchase and sale of reserves, net	(237,409		)		(20,529		)		—
Revision of estimates	121,916				(1,219,609		)		(224,784		)
Accretion of discount	50,821				196,315				197,902
Net change in income taxes	(86,667		)		560,485				1,404
Change in timing and other differences	13,575				156,031				(4,626		)
Net increase (decrease)	$	107,928			$	(1,019,733	)		$	(51,525	)

Significant_Accounting_Policie1

Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]	'
Basis Of Presentation	'
	Basis of Presentation
	Our consolidated financial statements include our accounts and those of all of our majority-owned subsidiaries, companies over which we exercise control through majority voting rights or other means of control and variable interest entities of which we are the primary beneficiary. We eliminate all inter-company balances and transactions in preparing consolidated financial statements. We account for our ownership in unincorporated partnerships and companies, including our prior interest in BBEP, under the equity method when we have significant influence over those entities, but because of terms of the ownership agreements, we do not meet the criteria for consolidation of the entities.
Use Of Estimates	'
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires our management to make estimates and assumptions that affect the reported amounts of certain assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenue and expense during each reporting period. Management believes its estimates and assumptions are reasonable, but such estimates and assumptions are subject to a number of risks and uncertainties, which may cause actual results to differ materially from management’s estimates.
	Significant estimates underlying these financial statements include the estimated quantities of our proved reserves (including the associated future net cash flows from those proved reserves and costs to develop those reserves) used to compute depletion expense, the full cost ceiling limitation and estimates of current revenue. Other estimates that require assumptions concerning future events and substantial judgment include the estimated fair value of derivatives, asset retirement obligations and stock-based compensation. Income taxes also involve the use of considerable judgment in the estimation and evaluation of deferred income tax assets and our ability to recover operating loss carry-forwards and assessment of uncertain tax positions.
Cash Equivalents	'
	Cash Equivalents
	Cash equivalents consist of time deposits and liquid debt investments with original maturities of three months or less at the time of purchase.
Accounts Receivable	'
	Accounts Receivable
	We sell our production to various purchasers, each of which is reviewed as to credit worthiness prior to the extension of credit and on a regular basis thereafter. Although we rarely require collateral, we require appropriate credit ratings and, in some instances, obtain parental guarantees. Receivables are generally collected within 30 to 60 days. When collections of specific amounts due are no longer reasonably assured, we establish an allowance for doubtful accounts though we have not had a significant instance of nonpayment. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers individually accounted for 21% and 15% of cash collected for our production revenue. During 2011, two purchasers accounted for 15% and 11% of cash collected for our production revenue.
Hedging And Derivatives	'
	Hedging and Derivatives
	We enter into derivatives to mitigate risk associated with the prices received from our natural gas, NGL and oil production. We may also utilize derivatives to hedge the risk associated with interest rates on our outstanding debt. All derivatives are recognized as either an asset or liability on the balance sheet measured at their fair value determined by reference to published future market prices and interest rates.
	Effective December 31, 2012, we discontinued the use of hedge accounting on all existing hedge contracts. Net deferred hedge gains deferred in AOCI associated with these contracts as of December 31, 2012 are reclassified to earnings during the same periods in which the hedged transactions are recognized in our earnings. Since then, we recognize changes in the fair values of derivative contracts as gains or losses in the earnings of the periods in which they occur.
	We enter into derivatives with counterparties who are our lenders at the inception of the derivative. Our credit facility provides for collateralization of amounts outstanding from our derivatives in addition to amounts outstanding under the facility. Additionally, default on any of our obligations under derivatives with counterparty lenders could result in acceleration of the amounts outstanding under the credit facility. Our credit facility and our internal credit policies require that any counterparties, including facility lenders, with whom we enter into commodity derivatives have credit ratings that meet or exceed BBB- or Baa3 from Standard and Poor’s or Moody’s, respectively. The fair value for each derivative takes credit risk into consideration, whether it be our counterparties’ or our own. Derivatives are classified as current or non-current derivative assets and liabilities, based on the expected timing of settlements.
Investments In Equity Affiliates	'
	Investments in Equity Affiliates
	During December 2011, we liquidated our investment in BBEP which we had accounted for using the equity method. Prior to this liquidation, we reviewed our investment for impairment whenever events or circumstances indicated that the investment’s carrying amount may not be recoverable. We recorded our portion of BBEP’s earnings during the quarter in which its financial statements became publicly available. Consequently, our 2011 annual results of operations include BBEP’s earnings for the 12 months ended September 30, 2011. Note 7 contains more information on our BBEP investment.
Property, Plant and Equipment	'
	Property, Plant, and Equipment
	We follow the full cost method in accounting for our oil and gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and gas properties are capitalized and accumulated in separate Canadian and U.S. cost centers. This includes any internal costs that are directly related to development and exploration activities, but does not include any costs related to production, general corporate overhead or similar activities. Proceeds received from disposals reduce the accumulated cost except when the sale represents a significant disposal of reserves, in which case a gain or loss is calculated and recognized. The sum of net capitalized costs and estimated future development and dismantlement costs for each cost center is depleted on the equivalent unit-of-production method, based on proved reserves. We may, at our option, exclude costs associated with unevaluated properties from amounts subject to depletion.
	Under the full cost method, net capitalized costs are limited to the lower of unamortized cost reduced by the related net deferred tax liability and asset retirement obligations (collectively, “the cost center ceiling”). The cost center ceiling equals the sum of (1) estimated future net revenue from proved reserves, discounted at 10% per annum, including the effects of derivatives that are accounted for as hedges of our oil and gas revenue, (2) the cost of properties not being amortized, (3) the lower of cost or market value of unproved properties included in the cost being amortized, less (4) income tax effects related to differences between the book and tax basis of the natural gas and oil properties. If the net book value reduced by the related net deferred income tax liability, unless in a valuation allowance, and asset retirement obligations exceeds the cost center ceiling limitation, a non-cash impairment charge is required. Note 8 to these financial statements contains further discussion of the ceiling test.
	Other properties and equipment are stated at original cost and depreciated using the straight-line method based on estimated useful lives ranging from five to forty years. If indicators of impairment are identified, an undiscounted cash flow analysis is performed to determine if an impairment exists. If the undiscounted cash flow analysis indicates an impairment, a discounted cash flow analysis is performed and the asset is reduced to the indicated value.
Inventory	'
	Inventory
	Inventories are primarily comprised of materials and parts including oil and gas drilling or repair items such as tubing, casing, chemicals, operating supplies and ordinary maintenance materials and parts. The materials, parts and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or fair value, on a first-in, first-out cost basis. Fair value represents net realizable value, which is the amount that we are allowed to bill to the joint accounts under joint operating agreements to which we are a party. Impairments for materials and supplies inventories are recorded as lease operating expense in the accompanying consolidated statements of operations.
Asset Retirement Obligations	'
	Asset Retirement Obligations
	We record the fair value of the liability for asset retirement obligations in the period in which it is legally or contractually incurred. Upon initial recognition of the asset retirement liability, an asset retirement cost is capitalized by increasing the carrying amount of the asset by the same amount as the liability. In periods subsequent to initial measurement, the asset retirement cost is recognized as expense through depletion or depreciation over the asset’s useful life. Changes in the liability for the asset retirement obligations are recognized for (1) the passage of time and (2) revisions to either the timing or the amount of estimated cash flows. Accretion expense is recognized for the impacts of increasing the discounted liability to its estimated settlement value.
Revenue Recognition	'
	Revenue Recognition
	Revenue is recognized when title to the products transfers to the purchaser. We use the “sales method” to account for our production revenue, whereby we recognize revenue on all production sold to our purchasers, regardless of whether the sales are proportionate to our ownership in the property. A receivable or liability is recognized only to the extent that we have an imbalance on a specific property greater than the expected remaining proved reserves. As of December 31, 2013 and 2012, our aggregate production imbalances were not material.
Environmental Compliance and Remediation	'
	Environmental Compliance and Remediation
	Environmental compliance costs, including ongoing maintenance and monitoring, are expensed as incurred. Those environmental remediation costs which improve a property are capitalized.
Debt	'
	Debt
	We record all debt instruments at face value. When an issuance of debt is made at other than par, a discount or premium is separately recorded. The discount or premium is amortized over the life of the debt using the effective interest method.
Income Taxes	'
	Income Taxes
	Deferred income taxes are established for all temporary differences between the book and the tax basis of assets and liabilities. In addition, deferred tax balances must reflect tax rates expected to be in effect in years in which the temporary differences reverse. Canadian taxes are calculated at rates expected to be in effect in Canada. U.S. deferred tax liabilities are not recognized on profits that are expected to be permanently reinvested in Canada and thus not considered available for distribution to the parent company. It is not practicable to determine our unrecognized deferred tax liability for temporary differences related to investments in foreign subsidiaries that are essentially permanent in duration. Net operating loss carry-forwards and other deferred tax assets are reviewed annually for recoverability, and, if necessary, are recorded net of a valuation allowance. Note 13 contains additional discussion regarding income taxes.
Stock-Based Compensation	'
	Stock-based Compensation
	We measure and recognize compensation expense for all share-based payment awards made to employees and directors based on their estimated fair value at the time the awards are granted. Our board of directors may elect to issue awards payable in cash. For awards with service requirements, we recognize the expense associated with the awards over the vesting period. The liability for fair value of cash awards is reassessed at every balance sheet date, such that the vested portion of the liability is adjusted to reflect revised fair value through compensation expense. For awards that vest only upon achievement of performance criteria, recognition is recorded only when achievement of the performance criteria is considered probable.
Disclosure of Fair Value of Financial Instruments	'
	Disclosure of Fair Value of Financial Instruments
	Our financial instruments include cash, commercial paper, time deposits, accounts receivable, notes payable, accounts payable, long-term debt and financial derivatives. The fair value of long-term debt is estimated as the present value of future cash flows discounted at rates consistent with comparable maturities and includes consideration of credit risk. The carrying amounts reflected in the balance sheet for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value.
Foreign Currency Translation	'
	Foreign Currency Translation
	Our Canadian subsidiary maintains its general ledger using the Canadian dollar. All balance sheet accounts of our Canadian operations are translated into U.S. dollars at the period end exchange rate and statement of income items are translated at the weighted average exchange rate for the period. The resulting translation adjustments are made directly to a component of accumulated other comprehensive income within stockholders’ equity. Gains and losses from foreign currency transactions are included in the consolidated results of operations.
Variable Interest Entities	'
	Variable Interest Entities
	An entity is a variable interest entity (VIE) if it meets the following criteria: (1) the entity has equity that is insufficient to permit the entity to finance its activities without additional subordinated financial support from other parties, or (2) the entity has equity investors that cannot make significant decisions about the entity’s operations or that do not absorb their proportionate share of the expected losses or receive the expected returns of the entity.
	VIEs require assessment of who the primary beneficiary is and whether the primary beneficiary should consolidate the VIE. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the variable interest entity that most significantly impacts the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the variable interest entity. Application of the VIE consolidation requirements may require the exercise of significant judgment by management.
	In 2011, we began to include the financial position of Fortune Creek and the results of operations were included beginning with the period ended December 31, 2012 in our consolidated financial statements. The results from operations of Fortune Creek for 2011 were immaterial. Note 15 contains additional discussion regarding Fortune Creek.
Earnings per Share	'Earnings per ShareWe report basic earnings per common share, which excludes the effect of potentially dilutive securities, and diluted earnings per common share, which includes the effect of all potentially dilutive securities unless their impact is antidilutive. Note 17 includes the calculation of earnings per share.

Derivatives_And_Fair_Value_Mea1

Derivatives And Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
Credit Risk Derivatives, at Fair Value, Net [Abstract]	'
Estimated Fair Value Of Derivative Instruments Under Input Levels	'
		Asset Derivatives							Liability Derivatives
		As of December 31,							As of December 31,
		2013				2012			2013			2012
		(in thousands)							(in thousands)
	Level 2 inputs	$	107,395			$	207,042		$	3,448		$	959
	Level 3 inputs	23,485				11,595			—			16,526
	Total	$	130,880			$	218,637		$	3,448		$	17,485
Changes In Level 3 Fair Values	'
		As of December 31,
		2013				2012
		(In thousands)
	Balance at beginning of period	$	(4,931	)		$	150,989
	Total gains (losses) for the period:
	Unrealized gain on derivatives	40,398				19,451
	Transfers out of Level 3	—				(180,732		)
	Settlements in production revenue	—				(3,738		)
	Settlements in net derivative losses	(11,982		)		(25,203		)
	Unrealized gains reported in OCI	—				34,302
	Balance at end of period	$	23,485			$	(4,931	)
	Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	41,909			$	19,451
Price Collars And Swaps For Anticipated Natural Gas Production	'
	Production		Daily Production
	Year		Volume
			Natural Gas		NGL		Natural Gas Basis Swaps
			MMcfd		MBbld		MMcfd
	2014 (1)		170		4		40
	2015		150		—		—
	2016-2021		40		—		—
	-1	Our 2014 NGL derivatives end in September. Our natural gas derivatives and AECO to NYMEX natural gas basis swaps are in place for the whole of 2014.
Net Deferred Hedge Gain in AOCI to be Released into Earnings in a Future Period [Table Text Block]	'
		(In thousands)
	2014	$	37,084
	2015	33,191
	2016	13,476
	2017	12,531
	2018 and thereafter	$	41,443
		$	137,725
Reduction Of Interest Expense Over The Life Of The Debt Instruments	'
		(In thousands)
	2014	2,039
	2015	2,194
	2016	569
		$	4,802
Estimated Fair Value Of Derivative Instruments	'
		Asset Derivatives								Liability Derivatives
		As of December 31,								As of December 31,
		2013				2012				2013			2012
		(In thousands)								(In thousands)
	Derivatives not designated as hedges:
	Commodity contracts reported in:
	Current derivative assets	$	60,063			$	113,367			$	2,540		$	—
	Noncurrent derivative assets	105,315				107,542				31,958			2,272
	Current derivative liabilities	—				—				3,125			—
	Noncurrent derivative liabilities	—				92				323			17,577
	Total derivatives not designated as hedges	$	165,378			$	221,001			$	37,946		$	19,849
Carrying Value Of Derivatives	'
		For the Year Ended December 31, 2012
		Commodity Hedges
		(In thousands)
	Derivative fair value at beginning of period	$	342,799
	Settlements in production revenue	(176,084		)
	Settlements in net derivative gains	(3,820		)
	Ineffectiveness reported in net derivative gains	1,281
	Unrealized gains reported in OCI	107,112
	Derecognition of hedge	(271,288		)
	Derivative fair value at end of period	$	—
Held-to-maturity Securities	'
		Amortized Cost				Gross Unrealized Gains			Gross Unrealized Losses			Fair Market Value
		(In thousands)
	Marketable securities (held-to-maturity)
	Time deposits	$	29,419			$	—		$	(22	)	$	29,397
	Commercial paper	136,924				27			(25		)	136,926
	Marketable securities	$	166,343			$	27		$	(47	)	$	166,323

Accounts_Receivable_Tables

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2013
Accounts Receivable, Net [Abstract]	'
Schedule Of Accounts Receivable	'
		As of December 31,
		2013			2012
		(In thousands)
	Accrued production revenue	$	34,785		$	49,762
	Joint interest billings	15,630			10,957
	Income taxes	7,931			—
	Canadian value added taxes	60			172
	NGL hedge settlement accrual	—			3,149
	Other	328			160
	Allowance for doubtful accounts	(89		)	(51		)
		$	58,645		$	64,149

Other_Current_Assets_Tables

Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Other Current Assets [Abstract]	'
Other Current Assets	'
		As of December 31,
		2013		2012
		(In thousands)
	Inventories	$	18,334	$	21,454
	Deposits	1,044		513
	Other prepaid expense	2,968		3,079
		$	22,346	$	25,046

Investment_In_BBEP_Tables

Investment In BBEP (Tables)	12 Months Ended
	Dec. 31, 2013
Equity Method Investment, Summarized Financial Information [Abstract]	'
Schedule of Operations Statement [Table Text Block]	'
		For the Twelve
		Months Ended
		September 30, 2011
		(in thousands)
	Revenue (1)	$	425,386
	Operating expense	313,388
	Operating income	111,998
	Interest and other (2)	40,759
	Income tax (benefit) expense	1,070
	Noncontrolling interests	183
	Net income available to BBEP	$	69,986
	Net income available to common unitholders	$	69,986
	(1)	For the twelve months ended September 30, 2011, unrealized gains of $24.0 million on commodity derivatives were recognized.
	(2)	The twelve months ended September 30, 2011 included $3.3 million for unrealized gains on interest rate swaps.

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment [Abstract]	'
Schedule Of Property, Plant And Equipment	'
		As of December 31,
		2013				2012
		(In thousands)
	Oil and gas properties
	Subject to depletion	$	5,687,557			$	5,770,913
	Unevaluated costs	221,605				307,267
	Accumulated depletion	(5,268,719		)		(5,297,220		)
	Net oil and gas properties	640,443				780,960
	Other property and equipment
	Pipelines and processing facilities	347,093				375,248
	General properties	72,125				75,147
	Accumulated depreciation	(198,856		)		(202,297		)
	Net other property and equipment	220,362				248,098
	Property, plant and equipment, net of accumulated depletion and depreciation	$	860,805			$	1,029,058
Schedule Of Charges For Impairment	'
				Pre-tax Charges for Impairment
		Segment		2013				2012				2011
				(in thousands)
	U.S.
	Oil and gas properties	Exploration and production		$	—			$	2,152,128			$	—
	Other property and equipment	Midstream		54				7,328				57,996
	Other property and equipment	Exploration and production		1,809				537				—
	Canada
	Oil and gas properties	Exploration and production		—				465,935				49,063
				$	1,863			$	2,625,928			$	107,059
Schedule Of Unevaluated Natural Gas And Oil Properties Not Subject To Depletion	'
		December 31, 2013 Costs Incurred During																December 31, 2012 Costs Incurred During
		2013				2012				2011				Prior		Total		2012		2011		2010		Prior		Total
		(In thousands)																(In thousands)
	U.S.
	Acquisition costs	$	—			$	3,013			$	13,484			$	—	$	16,497	$	6,844	$	42,339	$	1,447	$	32,429	$	83,059
	Exploration costs	14				364				—				—		378		2,676		207		—		—		2,883
	Capitalized interest	1,093				1,374				—				—		2,467		4,093		—		—		—		4,093
	Total U.S.	$	1,107			$	4,751			$	13,484			$	—	$	19,342	$	13,613	$	42,546	$	1,447	$	32,429	$	90,035
	Canada
	Acquisition costs	$	—			$	2,956			$	1,300			$	68,586	$	72,842	$	333	$	—	$	643	$	80,488	$	81,464
	Exploration costs	$	7,044			$	31,746			$	41,092			$	30,413	$	110,295	$	36,356	$	44,837	$	18,500	$	20,171	$	119,864
	Capitalized interest	$	3,947			$	2,724			$	3,522			$	8,933	$	19,126	$	2,796	$	3,614	$	2,830	$	6,664	$	15,904
	Total Canada	$	10,991			$	37,426			$	45,914			$	107,932	$	202,263	$	39,485	$	48,451	$	21,973	$	107,323	$	217,232
	Total	$	12,098			$	42,177			$	59,398			$	107,932	$	221,605	$	53,098	$	90,997	$	23,420	$	139,752	$	307,267
Schedule Of Unevaluated Property Costs	'
		As of December 31,
		2013				2012
		(In thousands)
	Barnett Shale	$	—			$	40,716
	West Texas	19,343				49,318
	Horn River Basin	202,262				217,233
	Total	$	221,605			$	307,267

Other_Assets_Tables

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2013
Other Assets, Noncurrent Disclosure [Abstract]	'
Schedule Of Other Assets	'
		As of December 31,
		2013			2012
		(In thousands)
	Deferred financing costs	$	84,951		$	59,059
	Less accumulated amortization	(50,171		)	(27,335		)
	Net deferred financing costs	34,780			31,724
	Governmental and notes receivable	6,464			7,385
	Other	360			838
		$	41,604		$	39,947

Accrued_Liabilities_Tables

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2013
Accrued Liabilities [Abstract]	'
Schedule Of Accrued Liabilities	'
		As of December 31,
		2013		2012
		(In thousands)
	Interest payable	$	38,260	$	67,116
	Accrued operating expense	37,747		38,733
	Prepayments from partners	425		—
	Revenue payable	22,589		21,013
	Accrued state income and franchise taxes	1,080		1,183
	Accrued production and property taxes	870		609
	Environmental liabilities	36		122
	Accrued product purchases	270		336
	Current asset retirement obligations	433		577
	Other	1,140		971
		$	102,850	$	130,660

LongTerm_Debt_Tables

Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Debt Instrument [Line Items]

'

'

Schedule of Long-term Debt Instruments [Table Text Block]

'

'

As of December 31,

2013

2012

(In thousands)

Combined Credit Agreements

$

211,200

$

388,150

Second Lien Term Loan, net of unamortized discount of $17,428

607,572

—

Second Lien Notes due 2019, net of unamortized discount of $5,577

194,423

—

Senior notes due 2015, net of unamortized discount of $30 and $2,149

10,472

435,851

Senior notes due 2016, net of unamortized discount of $105 and $10,825

8,044

579,795

Senior notes due 2019, net of unamortized discount of $4,757 and $5,378

293,243

292,622

Senior notes due 2021, net of unamortized discount of $15,810

309,190

—

Senior subordinated notes due 2016

350,000

350,000

Total debt

1,984,144

2,046,418

Unamortized deferred gain—terminated interest rate swaps

4,802

16,788

Long-term debt

$

1,988,946

$

2,063,206

Schedule of Maturities of Long-term Debt

'

'

2014

2015

2016

2017

2018

Thereafter

(in thousands)

Combined Credit Agreements

—

—

211,200

—

—

—

Second Lien Term Loan

—

—

—

—

—

625,000

Second Lien Notes due 2019

—

—

—

—

—

200,000

Senior notes due 2015

—

10,502

—

—

—

—

Senior notes due 2016

—

—

8,149

—

—

—

Senior notes due 2019

—

—

—

—

—

298,000

Senior notes due 2021

—

—

—

—

—

325,000

Senior subordinated notes due 2016

—

—

350,000

—

—

—

Total Indebtedness

—

10,502

569,349

—

—

1,448,000

Schedule of Debt

'

'

-1

Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilver’s domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the “Domestic Pledged Equity”), 65% of the equity interests of Quicksilver Resources Canada Inc. (“Quicksilver Canada”) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the “Domestic Pledged Property”). Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

Priority on Collateral and Structural Seniority (1)

Highest priority

Lowest priority

-2

The principal amount for the Combined Credit Agreements represents the global borrowing base as of December 31, 2013.

First Lien

Second Lien

Senior Unsecured

Senior Subordinated

Combined Credit

Second Lien Term Loan

Second Lien Notes due 2019

2015

2016

2019

2021

Senior

-3

The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding is greater than $100 million.

Agreements

Senior Notes

Senior Notes

Senior Notes

Senior Notes

Subordinated Notes

Principal amount (2)

$350 million

$625 million

$200 million

$11 million

$8 million

$298 million

$325 million

$350 million

-4

Represents the weighted average borrowing rate payable to lenders.

Scheduled maturity date (3)

September 6, 2016

June 21, 2019

June 21, 2019

August 1, 2015

January 1, 2016

August 15, 2019

July 1, 2021

April 1, 2016

Interest rate on outstanding borrowings at December 31, 2013 (4)

3.95%

7.00%

7.00%

8.25%

11.75%

9.13%

11.00%

7.12%

-5

Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a) the prime rate announced by JPMorgan, (b) the federal funds rate plus 0.50% and (c) adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario, (ii) an applicable margin between 1.75% and 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

Base interest rate

LIBOR, ABR, CDOR

LIBOR floor of 1.25%; ABR floor of 2.25%

LIBOR floor of 1.25%

N/A

N/A

N/A

N/A

N/A

options (5)(6)

-6

Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i) the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii) the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii) the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv) adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. We pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

Financial covenants (7)

- Minimum current ratio of 1.0

N/A

N/A

N/A

N/A

N/A

N/A

N/A

- Minimum EBITDA to cash interest expense ratio of 1.10

-7

The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

- Maximum senior secured debt leverage ratio of 2.0

Significant restrictive covenants (7)

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

- Asset sales

- Asset sales

- Incurrence of debt

- Incurrence of debt

- Incurrence of debt

-8

The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (“Level 2” inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (“Level 3” input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (“Level 1” input).

- Incurrence of liens

- Incurrence of liens and 1st lien cap

- Incurrence of liens and 1st lien cap

- Incurrence of liens

- Incurrence of liens

- Incurrence of liens

- Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

-Payment of dividends

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Equity purchases

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Asset sales

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Affiliate transactions

- Limitations on derivatives and investments

Optional redemption (7)

Any time

Any time, subject to re-pricing event

Any time, subject to re-pricing event

August 1,

July 1,

August 15,

July 1,

April 1,

June 21,

June 21,

2013: 101.938

2013: 105.875

2014: 104.563

2019: 102.000

2013: 101.188

2014: 102

2014: 102

2014: par

2014: 102.938

2015: 103.042

2020: par

2014: par

2015: 101

2015: 101

2015: par

2016: 101.521

2017: par

Make-whole redemption (7)

N/A

N/A

N/A

N/A

N/A

Callable prior to

Callable prior to

N/A

15-Aug-14

July 1, 2019 at

at make-whole

make-whole call price of

call price of

Treasury +50 bps

Treasury +50 bps

Change of control (7)

Event of default

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

Put at 101% of

principal plus

principal plus

principal plus

principal plus

principal plus

principal plus

principal plus

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

accrued interest

Equity clawback (7)

N/A

N/A

N/A

N/A

N/A

N/A

Redeemable until

N/A

1-Jul-16

at 111.00%, plus

accrued interest

for up to 35%

Estimated fair value (8)

$211.2 million

$625 million

$200 million

$10.6 million

$7.8 million

$298 million

$354.3 million

$341.3 million

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2013
Asset Retirement Obligation [Abstract]	'
Estimated Asset Retirement Obligation Activity	'
		As of December 31,
		2013			2012
		(In thousands)
	Beginning asset retirement obligations	$	116,526		$	85,822
	Additional liability incurred	3,922			4,072
	Change in estimates	7,582			21,080
	Accretion expense	5,109			4,122
	Asset retirement costs incurred	(1,560		)	(1,846		)
	Settlement of liability in excess of obligation recorded	742			2,229
	Disposition	(21,935		)	—
	Currency translation adjustment	(3,697		)	1,047
	Ending asset retirement obligations	106,689			116,526
	Less current portion	(433		)	(577		)
	Long-term asset retirement obligation	$	106,256		$	115,949

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
Components of Deferred Tax Assets and Liabilities [Abstract]	'
Significant Components Of Deferred Tax Assets And Liabilities	'
		As of December 31,
		2013				2012
		(In thousands)
	Deferred tax assets:
	Property, plant and equipment	$	209,134			$	483,771
	Net operating loss carry-forwards	183,982				109,100
	Investment in Fortune Creek	3,763				3,763
	AMT tax credit	47,883				55,814
	Settlements of interest rate swaps	1,681				5,876
	Deferred compensation expense	11,711				11,141
	State	3,680				—
	Other	791				2,710
	Deferred tax assets	462,625				672,175
	Deferred tax liabilities:
	Net derivative gains	(44,039		)		(73,195		)
	Other	(991		)		—
	Deferred tax liabilities	(45,030		)		(73,195		)
	Net deferred tax asset (liability)	417,595				598,980
	Valuation allowance	(417,595		)		(598,980		)
	Total deferred tax asset (liability)	$	—			$	—
	Reflected in the consolidated balance sheets as:
	Current deferred income tax liability	$	—			$	—
	Non-current deferred income tax liability	—				—
		$	—			$	—
Components of net income (loss) before income tax	'
		2013				2012				2011
						(In thousands)
	U.S.	$	184,034			$	(2,142,730	)		$	146,090
	Canada	(7,866		)		(505,446		)		1,819
	Total	$	176,168			$	(2,648,176	)		$	147,909
Components Of Income Tax Expense	'
		2013				2012				2011
						(In thousands)
	Current state income tax expense (benefit)	$	900			$	1,752			$	(1,706	)
	Current U.S. federal income tax expense (benefit)	(7,931		)		—				(5,565		)
	Current Canadian income tax expense	—				—				642
	Total current income tax expense (benefit)	(7,031		)		1,752				(6,629		)
	Deferred U.S. federal income tax expense (benefit)	205,820				(763,639		)		58,890
	U.S. federal valuation allowance expense	(186,713		)		533,974				—
	Deferred state income tax expense (benefit)	(3,680		)		—				1,980
	State valuation allowance expense	3,680				—				—
	Deferred Canadian income tax expense (benefit)	827				(128,982		)		3,622
	Canadian valuation allowance expense	1,647				61,325				—
	Total deferred income tax expense (benefit)	21,581				(297,322		)		64,492
	Total income tax expense (benefit)	$	14,550			$	(295,570	)		$	57,863
Statutory Federal Income Tax Rate	'
		2013			2012			2011
	U.S. federal statutory tax rate	35	%		35	%		35	%
	Permanent differences	4.8	%		(0.06	)%		1.51	%
	State income taxes net of federal deduction	0.31	%		(0.04	)%		0.12	%
	Canadian income taxes	(0.26	)%		(1.93	)%		2.41	%
	Other	(0.15	)%		0.67	%		0.08	%
	Derivatives deferred in OCI	12.43	%		—	%		—	%
	Valuation allowance	(43.87	)%		(22.48	)%		—	%
	Effective income tax rate	8.26	%		11.16	%		39.12	%
Schedule of Unrecognized Tax Benefits	'
		As of
		December 31,
		2013			2012
		(In thousands)
	Beginning unrecognized tax benefits	$	—		$	9,219
	Changes	—			(9,219		)
	Ending unrecognized tax benefits	$	—		$	—

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2013
Loss Contingency [Abstract]	'
Summary Of Contractual Obligations	'
		GPT		Drilling Rig		Operating		Purchase
		Contracts (1)		Contracts (2)		Leases (3)		Obligations (4)
		(In thousands)
	2014	$	86,628	$	4,240	$	3,912	$	3,071
	2015	85,043		—		3,994		220
	2016	81,803		—		4,123		—
	2017	78,326		—		4,070		—
	2018	65,860		—		4,043		—
	Thereafter	140,624		—		12,996		—
	Total	$	538,284	$	4,240	$	33,138	$	3,291
	(1)	Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts.
	(2)	We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contract requires payment of a specified day rate of $20,000 for the entire lease term regardless of our utilization of the drilling rigs.
	(3)	We lease office buildings and other property under operating leases. Rent expense for operating leases with terms exceeding one month was $3.6 million in 2013, $4.2 million in 2012 and $4.8 million in 2011. Minimum payments have not been reduced by minimum sublease rentals of $2.2 million due in the future under noncancelable subleases.
	(4)	At December 31, 2013, we were under contract to purchase goods and services for use in field and gas plant operations.

Quicksilver_Stockholders_Equit1

Quicksilver Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2013
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'
Schedule Of Common Shares And Treasury Share Activity [Table Text Block]	'
		Common			Treasury
		Shares Issued			Shares Held
	Balance at January 1, 2011	175,524,816			5,050,450
	Stock options exercised	209,221			—
	Restricted stock activity	1,246,446			329,252
	Balance at December 31, 2011	176,980,483			5,379,702
	Stock options exercised	1,572			—
	Restricted stock activity	2,033,063			541,400
	Balance at December 31, 2012	179,015,118			5,921,102
	Stock options exercised	—			—
	Restricted stock activity	4,979,761			777,538
	Balance at December 31, 2013	183,994,879			6,698,640
Assumptions For The Black-Scholes Option Pricing Model For Stock Options Issued	'
		2013		2012		2011
	Weighted average grant date fair value	$1.05		$4.21		$9.16
	Weighted average risk-free interest rate	1.31%		1.14%		2.38%
	Expected life	4.9 years		6.0 years		6.0 years
	Weighted average volatility	68.97%		68.20%		66.77%
	Expected dividends	—		—		—
Stock Option Activity	'
		Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
							(In years)		(In thousands)
	Outstanding at January 1, 2013	4,979,980			$	10.23
	Granted	2,037,467			1.95
	Exercised	—			—
	Canceled	(85,004	)		6.63
	Expired	(160,865	)		8.86
	Outstanding at December 31, 2013	6,771,578			$	7.82	6.4		$	—
	Exercisable at December 31, 2013	4,576,677			$	9.3	5.3		$	—
Restricted Stock And Stock Unit Activity	'
		Payable in shares					Payable in cash
		Shares			Weighted		Shares			Weighted
					Average					Average
					Grant Date					Grant Date
					Fair Value					Fair Value
	Outstanding at January 1, 2013	3,099,135			$	8.48	678,217			$	7.71
	Granted	6,511,441			2.76		1,483,306			2.81
	Vested	(2,524,332	)		6.69		(284,406	)		8.51
	Canceled	(1,418,154	)		3.68		(304,776	)		3.86
	Outstanding at December 31, 2013	5,668,090			$	3.9	1,572,341			$	3.69

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2013
Earnings Per Share [Abstract]	'
Reconciliation Of Components Used To Compute Basic And Diluted Earnings (Loss) Per Common Share	'
		Years Ended December 31,
		2013			2012			2011
		(In thousands, except per share data)
	Net income (loss) attributable to Quicksilver	$	161,618		$	(2,352,606	)	$	90,046
	Basic income allocable to participating securities (1)	(4,252		)	—			(1,106		)
	Income (loss) available to shareholders	$	157,366		$	(2,352,606	)	$	88,940
	Weighted average common shares – basic	171,518			170,106			168,993
	Effect of dilutive securities (2)
	Share-based compensation awards	141			—			742
	Weighted average common shares — diluted	171,659			170,106			169,735
	Earnings (loss) per common share — basic	$	0.92		$	(13.83	)	$	0.53
	Earnings (loss) per common share — diluted	$	0.92		$	(13.83	)	$	0.52
	(1)	Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.
	(2)	For 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2013
Condensed Consolidating Financial Information [Abstract]	'
List of Subsidiaries	'
	Guarantor Subsidiaries -		Non-Guarantor Subsidiaries
	Restricted		Restricted		Unrestricted
	Cowtown Pipeline Funding, Inc.		Quicksilver Resources Canada Inc.		Makarios Resources International Holdings LLC (2)
	Cowtown Pipeline Management, Inc.		Cowtown Drilling Inc. (1)		1622834 Alberta Inc. (2)
	Cowtown Pipeline L.P.		Quicksilver Resources Partners Operating Ltd. (2)		Makarios Midstream Inc. (2)
	Cowtown Gas Processing L.P.		0942065 B.C. Ltd. (3)		Makarios Resources International Inc. (2)
	Barnett Shale Operating LLC (2)		0942069 B.C Ltd. (3)		Quicksilver Production Partners GP LLC (2)
	QPP Parent LLC (3)				Quicksilver Production Partners LP (2)
	QPP Holdings LLC (3)
	Silver Stream Pipeline Company LLC (3)
	-1	This entity was inactive for the three-year period ended December 31, 2013.
	(2)	These entities were created in 2011.
	(3)	These entities were created in 2012.
Condensed Consolidating Balance Sheets	'
	Condensed Consolidating Balance Sheets
		31-Dec-13
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	ASSETS
	Current assets	$	349,586			$	10,735		$	53,034		$	(19,642	)	$	393,713		$	909		$	1,110		$	(1,772	)	$	393,960
	Property and equipment	455,822				15,486			307,865			—			779,173			—			81,632			—			860,805
	Investment in subsidiaries (equity method)	(217,852		)		—			(33,840		)	217,852			(33,840		)	(33,840		)	—			67,680			—
	Other assets	472,792				—			32,892			(390,723		)	114,961			—			—			—			114,961
	Total assets	$	1,060,348			$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742		$	65,908		$	1,369,726
	LIABILITIES AND EQUITY
	Current liabilities	$	124,275			$	12,210		$	17,167		$	(19,642	)	$	134,010		$	888		$	1,671		$	(1,772	)	$	134,797
	Long-term liabilities	1,942,043				19,242			542,659			(390,723		)	2,113,221			—			1,546			126,132			2,240,899
	Quicksilver stockholders’ equity	(1,005,970		)		(5,231		)	(199,875		)	217,852			(993,224		)	(33,819		)	79,525			(58,452		)	(1,005,970		)
	Total liabilities and equity	$	1,060,348			$	26,221		$	359,951		$	(192,513	)	$	1,254,007		$	(32,931	)	$	82,742		$	65,908		$	1,369,726
		31-Dec-12
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	ASSETS
	Current assets	$	261,130			$	105,695		$	76,088		$	(222,586	)	$	220,327		$	13,250		$	391		$	(26,455	)	$	207,513
	Property and equipment	621,073				20,007			296,462			—			937,542			—			91,516			—			1,029,058
	Investment in subsidiaries (equity method)	(191,725		)		—			(42,883		)	191,725			(42,883		)	(42,905		)	—			85,788			—
	Other assets	346,972				—			41,865			(243,620		)	145,217			—			—			—			145,217
	Total assets	$	1,037,450			$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907		$	59,333		$	1,381,788
	LIABILITIES AND EQUITY
	Current liabilities	$	255,678			$	112,133		$	33,475		$	(222,586	)	$	178,700		$	13,230		$	2,316		$	(26,455	)	$	167,791
	Long-term liabilities	1,914,568				19,242			524,107			(243,620		)	2,214,297			—			1,585			130,912			2,346,794
	Quicksilver stockholders’ equity	(1,132,796		)		(5,673		)	(186,050		)	191,725			(1,132,794		)	(42,885		)	88,006			(45,124		)	(1,132,797		)
	Total liabilities and equity	$	1,037,450			$	125,702		$	371,532		$	(274,481	)	$	1,260,203		$	(29,655	)	$	91,907		$	59,333		$	1,381,788
Condensed Consolidating Statements Of Income	'
	Condensed Consolidating Statements of Income
		For the Year Ended December 31, 2013
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	Revenue	$	416,516			$	788		$	144,258		$	—		$	561,562		$	—		$	22,364		$	(22,364	)	$	561,562
	Operating expenses	329,975				346			118,481			—			448,802			—			9,808			(22,364		)	436,246
	Tokyo Gas Transaction gain	339,328				—			—			—			339,328			—			—			—			339,328
	Equity in net earnings of subsidiaries	(9,896		)		—			(6,682		)	9,896			(6,682		)	12,563			—			(5,881		)	—
	Operating income (loss)	415,973				442			19,095			9,896			445,406			12,563			12,556			(5,881		)	464,644
	Fortune Creek accretion	—				—			—			—			—			—			—			(19,245		)	(19,245		)
	Interest expense and other	(242,279		)		—			(26,959		)	—			(269,238		)	—			7			—			(269,231		)
	Income tax expense	(12,076		)		—			(2,474		)	—			(14,550		)	—			—			—			(14,550		)
	Net income (loss)	$	161,618			$	442		$	(10,338	)	$	9,896		$	161,618		$	12,563		$	12,563		$	(25,126	)	$	161,618
	Other comprehensive loss	(40,166		)		—			(11,446		)	—			(51,612		)	—			—			—			(51,612		)
	Equity in OCI of subsidiaries	(11,446		)		—			—			11,446			—			—			—			—			—
	Comprehensive income (loss)	$	110,006			$	442		$	(21,784	)	$	21,342		$	110,006		$	12,563		$	12,563		$	(25,126	)	$	110,006
		For the Year Ended December 31, 2012
		Quicksilver				Restricted			Restricted			Restricted			Quicksilver			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Subsidiary			and			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Eliminations			Restricted			Subsidiaries									Inc.
															Subsidiaries												Consolidated
		(In thousands)
	Revenue	$	611,477			$	4,574		$	95,887		$	(2,900	)	$	709,038		$	—		$	14,639		$	(14,639	)	$	709,038
	Operating expenses	2,643,690				4,109			577,696			(2,900		)	3,222,595			—			7,940			(14,639		)	3,215,896
	Crestwood earn-out	41,097				—			—			—			41,097			—			—			—			41,097
	Equity in net earnings of subsidiaries	(437,510		)		—			(12,747		)	437,510			(12,747		)	6,726			—			6,021			—
	Operating income (loss)	(2,428,626		)		465			(494,556		)	437,510			(2,485,207		)	6,726			6,699			6,021			(2,465,761		)
	Fortune Creek accretion	—				—			—			—			—			—			—			(19,472		)	(19,472		)
	Interest expense and other	(152,077		)		—			(10,914		)	—			(162,991		)	21			27			—			(162,943		)
	Income tax (expense) benefit	228,097				(163		)	67,658			—			295,592			—			—			(22		)	295,570
	Net income (loss)	$	(2,352,606	)		$	302		$	(437,812	)	$	437,510		$	(2,352,606	)	$	6,747		$	6,726		$	(13,473	)	$	(2,352,606	)
	Other comprehensive income (loss)	(57,273		)		—			3,908			—			(53,365		)	—			—			—			(53,365		)
	Equity in OCI of subsidiaries	3,908				—			—			(3,908		)	—			—			—			—			—
	Comprehensive income (loss)	$	(2,405,971	)		$	302		$	(433,904	)	$	433,602		$	(2,405,971	)	$	6,747		$	6,726		$	(13,473	)	$	(2,405,971	)
		For the Year Ended December 31, 2011
		Quicksilver				Restricted			Restricted			Consolidating			Quicksilver
		Resources Inc.				Guarantor			Non-Guarantor			Eliminations			Resources Inc.
						Subsidiaries			Subsidiaries						Consolidated
		(In thousands)
	Revenue	$	778,741			$	4,573		$	163,864		$	(3,555	)	$	943,623
	Operating expenses	603,582				64,476			156,516			(3,555		)	821,019
	Equity in net earnings of subsidiaries	(40,725		)		—			—			40,725			—
	Operating income (loss)	134,434				(59,903		)	7,348			40,725			122,604
	Income from earnings of BBEP	(8,439		)		—			—			—			(8,439		)
	Interest expense and other	39,252				18			(5,526		)	—			33,744
	Income tax (expense) benefit	(75,201		)		20,960			(3,622		)	—			(57,863		)
	Net income (loss)	$	90,046			$	(38,925	)	$	(1,800	)	$	40,725		$	90,046
	Other comprehensive income (loss)	67,493				—			17,178			(17,178		)	67,493
	Equity in OCI of subsidiaries	17,178				—			—			—			17,178
	Comprehensive income (loss)	$	174,717			$	(38,925	)	$	15,378		$	23,547		$	174,717
Condensed Consolidating Statements Of Cash Flows	'
	Condensed Consolidating Statements of Cash Flows
		For the Year Ended December 31, 2013
		Quicksilver				Restricted			Restricted			Quicksilver			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
		Resources Inc.				Guarantor			Non-Guarantor			and Restricted									Resources Inc.
						Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
		(In thousands)
	Net cash flow provided by (used in) operating activities	$	(78,565	)		$	—		$	16,456		$	(62,109	)	$	—		$	10,409		$	(51,700	)
	Capital expenditures	(67,263		)		—			(33,520		)	(100,783		)	—			(505		)	(101,288		)
	Proceeds from Tokyo Gas Transaction	463,999				—			—			463,999			—			—			463,999
	Proceeds from Synergy Transaction	42,297				—			—			42,297			—			—			42,297
	Proceeds from sale of properties and equipment	7,128				—			43			7,171			—			—			7,171
	Purchase of marketable securities	(213,738		)		—			—			(213,738		)	—			—			(213,738		)
	Maturities and sales of marketable securities	47,603				—			—			47,603			—			—			47,603
	Net cash flow provided by (used in) investing activities	280,026				—			(33,477		)	246,549			—			(505		)	246,044
	Issuance of debt	1,215,266				—			22,086			1,237,352			—			—			1,237,352
	Repayments of debt	(1,157,969		)		—			(150,413		)	(1,308,382		)	—			—			(1,308,382		)
	Debt issuance costs	(26,296		)		—			—			(26,296		)	—			—			(26,296		)
	Intercompany Note	(147,103		)		—			147,103			—			—			—			—
	Distribution of Fortune Creek Partnership funds	—				—			—			—			—			(14,965		)	(14,965		)
	Purchase of treasury stock	(1,927		)		—			—			(1,927		)	—			—			(1,927		)
	Net cash flow provided by (used in) financing activities	(118,029		)		—			18,776			(99,253		)	—			(14,965		)	(114,218		)
	Effect of exchange rates on cash	—				—			(1,755		)	(1,755		)	—			5,781			4,026
	Net increase in cash and equivalents	83,432				—			—			83,432			—			720			84,152
	Cash and equivalents at beginning of period	4,618				—			—			4,618			—			333			4,951
	Cash and equivalents at end of period	$	88,050			$	—		$	—		$	88,050		$	—		$	1,053		$	89,103
		For the Year Ended December 31, 2012
		Quicksilver				Restricted			Restricted			Quicksilver			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
		Resources Inc.				Guarantor			Non-Guarantor			and Restricted									Resources Inc.
						Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
		(In thousands)
	Net cash flow provided by operating activities	$	163,353			$	656		$	49,271		$	213,280		$	—		$	14,447		$	227,727
	Capital expenditures	(231,934		)		(656		)	(242,158		)	(474,748		)	—			(10,731		)	(485,479		)
	Proceeds from Crestwood earn-out	41,097				—			—			41,097			—			—			41,097
	Proceeds from sale of properties and equipment	72,362				—			363			72,725			—			—			72,725
	Net cash flow used in investing activities	(118,475		)		(656		)	(241,795		)	(360,926		)	—			(10,731		)	(371,657		)
	Issuance of debt	228,500				—			239,459			467,959			—			—			467,959
	Repayments of debt	(264,018		)		—			(46,412		)	(310,430		)	—			—			(310,430		)
	Debt issuance costs	(1,972		)		—			(1,050		)	(3,022		)	—			—			(3,022		)
	Distribution of Fortune Creek Partnership funds	—				—			—			—			—			(14,285		)	(14,285		)
	Proceeds from exercise of stock options	11				—			—			11			—			—			11
	Purchase of treasury stock	(3,144		)		—			—			(3,144		)	—			—			(3,144		)
	Net cash flow provided by (used in) financing activities	(40,623		)		—			191,997			151,374			—			(14,285		)	137,089
	Effect of exchange rates on cash	—				—			527			527			—			(1,881		)	(1,354		)
	Net increase (decrease) in cash and equivalents	4,255				—			—			4,255			—			(12,450		)	(8,195		)
	Cash and equivalents at beginning of period	363				—			—			363			—			12,783			13,146
	Cash and equivalents at end of period	$	4,618			$	—		$	—		$	4,618		$	—		$	333		$	4,951
		For the Year Ended December 31, 2011
		Quicksilver				Restricted			Restricted			Quicksilver			Fortune			Consolidating			Quicksilver
		Resources Inc.				Guarantor			Non-Guarantor			and Restricted			Creek			Eliminations			Resources Inc.
						Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
		(In thousands)
	Net cash flow provided by operating activities	$	202,043			$	2,225		$	48,785		$	253,053		$	—		$	—		$	253,053
	Capital expenditures	(518,454		)		(2,225		)	(169,928		)	(690,607		)	—			—			(690,607		)
	Proceeds from sale of BBEP units	272,965				—			—			272,965			—			—			272,965
	Investment in Fortune Creek	—				—			(12,783		)	(12,783		)	—			12,783			—
	Proceeds from sale of properties and equipment	2,959				—			1,204			4,163			—			—			4,163
	Net cash flow provided by (used in) investing activities	(242,530		)		(2,225		)	(181,507		)	(426,262		)	—			12,783			(413,479		)
	Issuance of debt	587,500				—			268,322			855,822			—			—			855,822
	Repayments of debt	(588,862		)		—			(254,246		)	(843,108		)	—			—			(843,108		)
	Debt issuance costs	(9,160		)		—			(3,346		)	(12,506		)	—			—			(12,506		)
	Proceeds from exercise of stock options	1,299				—			—			1,299			—			—			1,299
	Partnership funds received	—				—			—			—			135,696			(12,783		)	122,913
	Creation of partnership liability	—				—			122,913			122,913			(122,913		)	—			—
Purchase of treasury stock	(4,864		)		—			—			(4,864		)	—			—			(4,864		)
Net cash flow provided by (used in) financing activities	(14,087		)		—			133,643			119,556			12,783			(12,783		)	119,556
Effect of exchange rates on cash	—				—			(921		)	(921		)	—			—			(921		)
Net increase (decrease) in cash and equivalents	(54,574		)		—			—			(54,574		)	12,783			—			(41,791		)
Cash and equivalents at beginning of period	54,937				—			—			54,937			—			—			54,937
Cash and equivalents at end of period	$	363			$	—		$	—		$	363		$	12,783		$	—		$	13,146

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2013
Segment Reporting [Abstract]	'
Operating Income And Property And Equipment Costs Incurred	'
		Exploration & Production						Midstream									Quicksilver
		U.S.			Canada						Corporate			Elimination			Consolidated
		(In thousands)
	2013
	Revenue	$	416,462		$	141,870		$	25,594		$	—		$	(22,364	)	$	561,562
	DD&A	37,540			17,508			5,249			2,315			—			62,612
	Impairment expense	1,809			—			54			—			—			1,863
	Operating income (loss)	476,610			32,648			13,008			(57,622		)	—			464,644
	Property and equipment costs incurred	64,976			16,838			7,055			9,792			—			98,661
	2012
	Revenue	$	598,892		$	105,949		$	21,735		$	—		$	(17,538	)	$	709,038
	DD&A	123,370			32,686			5,182			2,386			—			163,624
	Impairment expense	2,152,665			465,935			7,328			—			—			2,625,928
	Operating income (loss)	(1,921,073		)	(474,768		)	8,163			(78,083		)	—			(2,465,761		)
	Property and equipment costs incurred	189,997			174,867			18,742			6,850			—			390,456
	2011
	Revenue	$	806,657		$	135,948		$	4,573		$	—		$	(3,555	)	$	943,623
	DD&A	171,438			47,116			4,889			2,320			—			225,763
	Impairment expense	—			49,063			57,996			—			—			107,059
	Operating income (loss)	251,495			12,914			(59,903		)	(81,902		)	—			122,604
	Property and equipment costs incurred	487,145			131,699			64,119			11,516			—			694,479
	Property, plant and equipment—net
	31-Dec-13	$	451,840		$	306,423		$	97,118		$	5,424		$	—		$	860,805
	31-Dec-12	614,071			294,921			111,523			8,543			—			1,029,058
	Total assets
	31-Dec-13	$	895,388		$	359,951		$	108,963		$	5,424		$	—		$	1,369,726
	31-Dec-12	784,104			371,532			217,609			8,543			—			1,381,788

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Cash Paid Or Received For Interest And Income Taxes	'
		Years Ended December 31,
		2013		2012			2011
		(In thousands)
	Interest, net of capitalized interest	$	254,901	$	154,663		$	170,814
	Income taxes	833		(20,682		)	(4,249		)
Other Significant Non-cash Transactions	'
		Years Ended December 31,
		2013		2012			2011
		(In thousands)
	Working capital related to capital expenditures	$	10,324	$	10,939		$	107,586
	Note receivable received for sale of land and building	—		—			5,300

Supplemental_Selected_Quarterl1

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Data [Abstract]	'
Schedule Of Quarterly Financial Data	'
		Quarter Ended
		March 31			June 30			September 30			December 31
		(In thousands, except per share data)
	2013 (1) (2) (3)
	Operating revenue	$	118,703		$	175,497		$	153,116		$	114,246
	Operating income (loss)	(3,874		)	394,894			60,049			13,575
	Net income (loss)	(59,707		)	242,523			10,577			(31,775		)
	Basic net earnings per share	$	(0.35	)	$	1.37		$	0.06		$	(0.18	)
	Diluted net earnings per share	(0.35		)	1.37			0.06			(0.18		)
	2012 (4) (5) (6) (7)
	Operating revenue	$	172,866		$	194,018		$	118,188		$	223,966
	Operating loss	(267,985		)	(1,153,012		)	(576,551		)	(468,213		)
	Net loss	(211,565		)	(802,022		)	(790,520		)	(548,499		)
	Basic net earnings per share	$	(1.24	)	$	(4.72	)	$	(4.65	)	$	(3.22	)
	Diluted net earnings per share	(1.24		)	(4.72		)	(4.65		)	(3.22		)
	(1)	Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.
	(2)	Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR.
	(3)	Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.
	(4)	Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.
	(5)	Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.
	(6)	Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of $359.9 million.
	(7)	Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Supplemental Oil and Gas Information [Line Items]	'
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]	'
	The changes in our proved reserves for the three years ended December 31, 2013 were as follows:
		Natural Gas (MMcf)									NGL (MBbl)						Oil (MBbl)
		U.S.			Canada			Total			U.S.		Canada		Total		U.S.		Canada	Total
	December 31, 2010	1,941,723			265,888			2,207,611			112,444		12		112,456		3,308		—	3,308
	Revisions (3)	(172,643	)		15,066			(157,577	)		(8,519	)	1		(8,518	)	(43	)	—	(43	)
	Extensions and discoveries (2)	155,662			76,067			231,729			2,652		—		2,652		43		—	43
	Production	(95,838	)		(26,390	)		(122,228	)		(4,432	)	(2	)	(4,434	)	(273	)	—	(273	)
	31-Dec-11	1,828,904			330,631			2,159,535			102,145		11		102,156		3,035		—	3,035
	Revisions (3)	(910,386	)		(33,945	)		(944,331	)		(45,379	)	1		(45,378	)	(479	)	—	(479	)
	Extensions and discoveries (2)	25,858			9			25,867			3,518		—		3,518		345		—	345
	Sales in place (1)	(20,616	)		—			(20,616	)		(42	)	—		(42	)	(85	)	—	(85	)
	Production	(75,712	)		(29,912	)		(105,624	)		(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)
	31-Dec-12	848,048			266,783			1,114,831			56,173		10		56,183		2,529		—	2,529
	Revisions (3)	234,835			28,648			263,483			750		—		750		62		—	62
	Extensions and discoveries (2)	50,992			9,697			60,689			—		—		—		—		—	—
	Sales in place (4)	(257,741	)		—			(257,741	)		(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)
	Production	(51,684	)		(39,372	)		(91,056	)		(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)
	31-Dec-13	824,450			265,756			1,090,206			39,734		9		39,743		199		—	199
	Proved developed reserves
	31-Dec-11	1,244,187			299,371			1,543,558			60,902		11		60,913		2,545		—	2,545
	31-Dec-12	725,361			266,783			992,144			47,284		10		47,294		2,416		—	2,416
	31-Dec-13	702,147			260,159			962,306			34,603		9		34,612		139		—	139
	Proved undeveloped reserves
	31-Dec-11	584,717			31,260			615,977			41,243		—		41,243		490		—	490
	31-Dec-12	122,687			—			122,687			8,890		—		8,890		113		—	113
	31-Dec-13	122,303			5,896			128,199			5,131		—		5,131		60		—	60
	(1)	Sales of reserves in place during 2012 relate to our agreement to allow an outside working interest owner to fund the completion costs for twelve wells in our Barnett Shale Asset for which they received a preferential right to reserves. It also includes a minimal sale of reserves in our Niobrara Asset to SWEPI.
	(2)	Extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for:
	•	2013 are attributable to our Barnett Shale Asset;
	•	2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed); and
	•	2011 are 100% attributable to our Barnett Shale Asset (of which 11% were proved developed).
	Canadian extensions and discoveries for:
	•	2013 and 2012 are attributable to our Horseshoe Canyon Asset; and
	•	2011 are 97% attributable to our Horn River Asset and 3% are attributable to our Horseshoe Canyon Asset.
	(3)	Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in economic factors of 419,972 MMcfe, (590,064) MMcfe and (54,539) MMcfe in 2013, 2012 and 2011, respectively, and changes in non-economic factors of (151,615) MMcfe, (629,407) MMcfe and (154,405) MMcfe in 2013, 2012 and 2011, respectively, including:
	•	Removal of proved undeveloped reserves that had not been developed within five years: (76) Bcfe and (250) Bcfe in 2013 and 2012, respectively;
	•	changes in performance related to offsetting activities, higher pipeline pressures and other factors: (74) Bcfe and (291) Bcfe in 2013 and 2012, respectively and
	•	revision of type curve of non producing wells based on comparison to producing analogs: (88) Bcfe in 2012.
	(4)	Sales of reserves in place during 2013 relate to the Tokyo Gas Transaction (337 Bcfe) and the Synergy Transaction (15 Bcfe).
Capitalized Costs Relating to Oil and Gas Producing Activities Disclosure [Table Text Block]	'
	The carrying value of our oil and gas assets as of December 31, 2013, 2012 and 2011 were as follows:
		U.S.				Canada				Consolidated
		(In thousands)
	2013
	Proved properties	$	4,645,777			$	1,041,780			$	5,687,557
	Unevaluated properties	19,343				202,262				221,605
	Accumulated DD&A	(4,268,387		)		(1,000,332		)		(5,268,719		)
	Net capitalized costs	$	396,733			$	243,710			$	640,443
	2012
	Proved properties	$	4,681,860			$	1,089,053			$	5,770,913
	Unevaluated properties	90,035				217,232				307,267
	Accumulated DD&A	(4,233,391		)		(1,063,829		)		(5,297,220		)
	Net capitalized costs	$	538,504			$	242,456			$	780,960
	2011
	Proved properties	$	4,380,745			$	928,585			$	5,309,330
	Unevaluated properties	252,737				180,604				433,341
	Accumulated DD&A	(1,965,258		)		(550,937		)		(2,516,195		)
	Net capitalized costs	$	2,668,224			$	558,252			$	3,226,476
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]	'
	Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2013, were as follows:
		U.S.				Canada				Consolidated
		(In thousands)
	2013
	Proved acreage	$	—			$	—			$	—
	Unproved acreage	15,843				6,305				22,148
	Development costs	49,299				17,422				66,721
	Exploration costs	—				—				—
	Total	$	65,142			$	23,727			$	88,869
	2012
	Proved acreage	$	—			$	—			$	—
	Unproved acreage	23,711				5,612				29,323
	Development costs	131,926				178,808				310,734
	Exploration costs	35,244				8,304				43,548
	Total	$	190,881			$	192,724			$	383,605
	2011
	Proved acreage	$	—			$	—			$	—
	Unproved acreage	145,099				—				145,099
	Development costs	304,373				90,361				394,734
	Exploration costs	37,673				41,338				79,011
	Total	$	487,145			$	131,699			$	618,844
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]	'
	Consolidated results of operations, without giving consideration to any tax valuation allowance, from our producing activities for each of the three years ended December 31, 2013, are set forth below:
		U.S.				Canada				Consolidated
		(In thousands)
	2013
	Natural gas, NGL and oil revenue	$	331,964			$	131,527			$	463,491
	Operating expense	167,425				80,475				247,900
	Depletion expense	34,995				5,362				40,357
		129,544				45,690				175,234
	Income tax expense	45,340				11,514				56,854
	Results from producing activities	$	84,204			$	34,176			$	118,380
	2012
	Natural gas, NGL and oil revenue	$	538,902			$	92,045			$	630,947
	Operating expense	226,542				60,501				287,043
	Depletion expense	116,005				24,897				140,902
	Impairment expense	2,152,128				465,935				2,618,063
		(1,955,773		)		(459,288		)		(2,415,061		)
	Income tax benefit	(684,521		)		(114,822		)		(799,343		)
	Results from producing activities	$	(1,271,252	)		$	(344,466	)		$	(1,615,718	)
	2011
	Natural gas, NGL and oil revenue	$	673,041			$	127,502			$	800,543
	Operating expense	267,890				54,770				322,660
	Depletion expense	164,493				38,228				202,721
	Impairment expense	—				49,063				49,063
		240,658				(14,559		)		226,099
	Income tax expense (benefit)	84,230				(4,222		)		80,008
	Results from producing activities	$	156,428			$	(10,337	)		$	146,091
Schedule of Prices used for Standardized Measure [Table Text Block]	'
	The following representative prices were used in the Standardized Measure and were adjusted by field for appropriate regional differentials:
		At December 31,
		2013				2012				2011
	Natural gas – Henry Hub, per MMBtu	$	3.67			$	2.76			$	4.12
	Natural gas – AECO, per MMBtu	2.9				2.35				3.65
	Oil – WTI Cushing, per Bbl	97.18				94.71				95.71
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]	'
	The Standardized Measure at December 31, 2013, 2012 and 2011 was as follows:
		U.S.				Canada				Total
						(In thousands)
	31-Dec-13
	Future revenue	$	3,825,944			$	656,984			$	4,482,928
	Future production costs	(2,022,977		)		(385,776		)		(2,408,753		)
	Future development costs	(212,280		)		(79,525		)		(291,805		)
	Future income taxes	(134,418		)		59,294				(75,124		)
	Future net cash flows	1,456,269				250,977				1,707,246
	10% discount	(801,116		)		(83,082		)		(884,198		)
	Standardized measure of discounted future cash flows relating to proved reserves	$	655,153			$	167,895			$	823,048
	31-Dec-12
	Future revenue	$	3,980,643			$	472,539			$	4,453,182
	Future production costs	(2,552,863		)		(324,424		)		(2,877,287		)
	Future development costs	(239,532		)		(56,354		)		(295,886		)
	Future income taxes	81,847				80,206				162,053
	Future net cash flows	1,270,095				171,967				1,442,062
	10% discount	(667,738		)		(59,204		)		(726,942		)
	Standardized measure of discounted future cash flows relating to proved reserves	$	602,357			$	112,763			$	715,120
	31-Dec-11
	Future revenue	$	11,647,002			$	1,055,711			$	12,702,713
	Future production costs	(5,496,246		)		(463,852		)		(5,960,098		)
	Future development costs	(1,125,641		)		(146,658		)		(1,272,299		)
	Future income taxes	(1,229,968		)		(44,183		)		(1,274,151		)
	Future net cash flows	3,795,147				401,018				4,196,165
	10% discount	(2,286,449		)		(174,863		)		(2,461,312		)
	Standardized measure of discounted future cash flows relating to proved reserves	$	1,508,698			$	226,155			$	1,734,853
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	'
	The primary changes in the Standardized Measure for 2013, 2012 and 2011 were as follows:
		Years Ended December 31,
		2013				2012				2011
						(In thousands)
	Sales of oil and gas net of production costs	$	(147,402	)		$	(149,326	)		$	(477,883	)
	Net changes in economic factors	326,698				(1,362,793		)		32,175
	Extensions and discoveries	43,328				27,003				251,635
	Development costs incurred	2,302				172,563				233,294
	Changes in estimated future development costs	20,766				620,127				(60,642		)
	Purchase and sale of reserves, net	(237,409		)		(20,529		)		—
	Revision of estimates	121,916				(1,219,609		)		(224,784		)
	Accretion of discount	50,821				196,315				197,902
	Net change in income taxes	(86,667		)		560,485				1,404
	Change in timing and other differences	13,575				156,031				(4,626		)
	Net increase (decrease)	$	107,928			$	(1,019,733	)		$	(51,525	)

Nature_Of_Operations_Nature_of

Nature Of Operations Nature of Operations (Details) (USD $)	Dec. 31, 2013	Mar. 31, 2013
In Millions, unless otherwise specified
Combined Credit Agreements [Member]	'	'
Debt Instrument [Line Items]	'	'
Available borrowing under combined credit agreements	$97.60	'
Combined Credit Agreements [Member]	'	'
Debt Instrument [Line Items]	'	'
Borrowing capacity	$350	$850

Significant_Accounting_Policie2

Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	customers	customers	customers
Significant Accounting Policies [Line Items]	'	'	'
Purchasers	1	2	2
Estimated future net revenue discount rate	10.00%	'	'
Maximum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Receivables number of due days	60	'	'
Minimum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Receivables number of due days	30	'	'
Purchaser One [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Purchases made by customer percentage	18.00%	21.00%	15.00%
Purchaser Two [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Purchases made by customer percentage	'	15.00%	11.00%
Other Property and Equipment [Member] | Maximum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'40 years	'	'
Other Property and Equipment [Member] | Minimum [Member]	'	'	'
Significant Accounting Policies [Line Items]	'	'	'
Estimated useful lives	'5 years	'	'

Divestitures_Narrative_Details

Divestitures (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended				3 Months Ended	12 Months Ended	0 Months Ended
	Dec. 31, 2013	Dec. 31, 2011	Sep. 30, 2013	Jun. 30, 2013	Apr. 30, 2013	Jun. 30, 2013	Dec. 31, 2013	Dec. 28, 2012	Dec. 31, 2013
	acre		Southern Alberta Basin [Member]	Barnett Shale [Member]	Barnett Shale [Member]	Tokyo Gas [Member]	Tokyo Gas [Member]	Acquisition and Exploration Agreement [Member]	Subsequent Event [Member]
								SWEPI LP [Member]	Sandwash Basin [Member]
								acre
Acquisitions And Divestitures [Line Items]	'	'	'	'	'	'	'	'	'
Approximate Gross Acres Eni West Texas Total	52,500	'	'	'	'	'	'	'	'
Area of Mutual Interest (AMI)	'	'	'	'	'	'	'	850,000	'
Working interest assigned to each party	'	'	'	'	'	'	'	50.00%	'
Percent ownership of AMI	'	'	'	'	'	'	'	50.00%	'
Area of AMI owned	'	'	'	'	'	'	'	320,000	'
Percentage right to any acquisition in the AMI	'	'	'	'	'	'	'	50.00%	'
Percentage of ownership interest	100.00%	'	'	'	25.00%	'	'	'	'
Acquisition cash transactions	'	$0	'	'	'	'	'	'	'
Equalization Payment Percentage	'	'	'	'	'	'	'	50.00%	'
Gain on sale of assets	'	0	'	'	'	'	339,328,000	'	'
Eni Funding of West Texas Transaction	52,000,000	'	'	'	'	'	'	'	'
Joint Interest Ownership After Complete Three Phases	50.00%	'	'	'	'	'	'	'	'
PurchasePricePriorToAdjustments	'	'	46,000,000	485,000,000	'	'	'	'	'
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	'	'	42,300,000	'	464,000,000	'	'	'	90,000,000
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax	'	'	'	'	339,300,000	'	'	'	'
Oil and Gas Property Decrease due to Gain	'	'	'	'	'	$110,700,000	'	'	'

Derivatives_And_Fair_Value_Mea2

Derivatives And Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2010
Senior notes maturity	'	'	'2015
Cash received in settlement of hedge	'	'	$41.50
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)	'	'	30.8
Interest previously accrued and earned	'	'	10.7
Gains and losses from the effective portion of derivative assets and liabilities held in AOCI expected to be reclassified into earnings	25	'	'
Reduction of interest expense over the life of a debt instruments	4.8	'	'
Gain (Loss) on Discontinuation of Interest Rate Cash Flow Hedge Due to Forecasted Transaction Probable of Not Occurring, Net	8.3	'	'
Interest Rate Cash Flow Hedge Gain (Loss) Reclassified to Earnings, Net	$12	$5.10	'
Fair Value, Inputs, Level 3 [Member]	'	'	'
Natural gas hedges original tenure	'10 years	'	'
Fair Value, Inputs, Level 3 [Member] | Maximum [Member]	'	'	'
Unobservable inputs included within the fair value calculation	4.8	'	'
Fair Value, Inputs, Level 3 [Member] | Minimum [Member]	'	'	'
Unobservable inputs included within the fair value calculation	4	'	'

Derivatives_And_Fair_Value_Mea3

Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments Under Input Levels) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Asset Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	$130,880	$218,637
Asset Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	107,395	207,042
Asset Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	23,485	11,595
Liability Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	3,448	17,485
Liability Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	3,448	959
Liability Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Estimated fair value of derivative instruments	$0	$16,526

Derivatives_And_Fair_Value_Mea4

Derivatives And Fair Value Measurements (Changes In Level 3 Fair Values) (Details) (Fair Value Inputs, Level 3 [Member], USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Balance at beginning of period	($4,931)	$150,989
Unrealized gain on derivatives	-40,398	19,451
Transfers out of Level 3	0	-180,732
Unrealized gains reported in OCI	0	-34,302
Balance at end of period	23,485	-4,931
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	41,909	19,451
Production Revenue [Member]	'	'
Settlements	0	-3,738
Derivative gains (losses) [Member]	'	'
Settlements	($11,982)	($25,203)

Derivatives_And_Fair_Value_Mea5

Derivatives And Fair Value Measurements (Swaps For Anticipated Natural Gas and NGL Production) (Details)	12 Months Ended
	Dec. 31, 2013
	MMcf
Credit Risk Derivatives, at Fair Value, Net [Abstract]	'
Gas 2014	170	[1]
NGL 2014	4	[1]
Anticipated Natural Gas Basis Swap Production For Second Year	40	[1]
Gas 2015	150
NGL 2015	0
Anticipated Natural Gas Basis Swap Production For Third Year	0
Gas 2016-2021	40
NGL 2016-2021	0
Anticipated Natural Gas Basis Swap Production Thereafter	0
[1]	Our 2014 NGL derivatives end in September. Our natural gas derivatives and AECO to NYMEX natural gas basis swaps are in place for the whole of 2014.

Derivatives_And_Fair_Value_Mea6

Derivatives And Fair Value Measurements (Net Deferred Hedge Gain in AOCI to be Released into Earnings) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Credit Risk Derivatives, at Fair Value, Net [Abstract]	'
2014	$37,084
2015	33,191
2016	13,476
2017	12,531
2018 and thereafter	41,443
Net deferred hedge gain in AOCI to be released into earnings	$137,725

Derivatives_And_Fair_Value_Mea7

Derivatives And Fair Value Measurements (Reduction Of Interest Expense Over The Life Of The Debt Instruments) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Credit Risk Derivatives, at Fair Value, Net [Abstract]	'
2014	$2,039
2015	2,194
2016	569
Reduction of interest expense over the life of the debt instruments, total	$4,802

Derivatives_And_Fair_Value_Mea8

Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'	'
Current derivative assets	$57,523	$113,367
Noncurrent derivative assets	73,357	105,270
Current derivative liabilities	3,125	0
Noncurrent derivative liabilities	323	17,485
Asset Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivative assets	165,378	221,001
Liability Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Total derivative liabilities	37,946	19,849
Not Designated as Hedging Instrument [Member] | Asset Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current derivative assets	60,063	113,367
Noncurrent derivative assets	105,315	107,542
Current derivative liabilities	0	0
Noncurrent derivative liabilities	0	92
Not Designated as Hedging Instrument [Member] | Liability Derivatives [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Current derivative assets	2,540	0
Noncurrent derivative assets	31,958	2,272
Current derivative liabilities	3,125	0
Noncurrent derivative liabilities	$323	$17,577

Derivatives_And_Fair_Value_Mea9

Derivatives And Fair Value Measurements (Carrying Value Of Derivatives) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivatives, Fair Value [Line Items]	'	'	'
Settlements in production revenue	$46,931	$128,161	$58,125
Commodity Hedges [Member]	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Derivative fair value at period start	'	342,799	'
Ineffectiveness reported in net derivative gains	'	1,281	'
Unrealized gains reported in OCI	'	-107,112	'
Derecognition of hedge	'	-271,288	'
Derivative fair value at end of period	'	0	'
Production Revenue [Member] | Commodity Hedges [Member]	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Settlements in production revenue	'	-176,084	'
Derivative gains (losses) [Member] | Commodity Hedges [Member]	'	'	'
Derivatives, Fair Value [Line Items]	'	'	'
Settlements in net derivative gains	'	$3,820	'

Recovered_Sheet1

Derivatives And Fair Value Measurements Derivatives, Investments And Fair Value Measurements (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013
Fixed Income Securities [Member]	'
Schedule of Held-to-maturity Securities [Line Items]	'
Held-to-maturity Securities, Fair Value	$29,397
Held-to-maturity Securities, Unrecognized Holding Loss	-22
Held-to-maturity Securities, Unrecognized Holding Gain	0
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	29,419
Commercial Paper, Not Included with Cash and Cash Equivalents [Member]	'
Schedule of Held-to-maturity Securities [Line Items]	'
Held-to-maturity Securities, Fair Value	136,926
Held-to-maturity Securities, Unrecognized Holding Loss	-25
Held-to-maturity Securities, Unrecognized Holding Gain	27
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	136,924
Debt Securities [Member]	'
Schedule of Held-to-maturity Securities [Line Items]	'
Held-to-maturity Securities, Fair Value	166,323
Held-to-maturity Securities, Unrecognized Holding Loss	-47
Held-to-maturity Securities, Unrecognized Holding Gain	27
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	$166,343

Accounts_Receivable_Schedule_O

Accounts Receivable (Schedule Of Accounts Receivable) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accounts Receivable, Net [Abstract]	'	'
Accrued production	$34,785	$49,762
Joint interest billings	15,630	10,957
Income taxes	7,931	0
Canadian value added taxes	60	172
NGL hedge settlement accrual	0	3,149
Other	328	160
Allowance for doubtful accounts	-89	-51
Accounts receivable, net	$58,645	$64,149

Other_Current_Assets_Details

Other Current Assets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Other Current Assets [Abstract]	'	'
Inventories	$18,334	$21,454
Deposits	1,044	513
Other prepaid expense	2,968	3,079
Other current assets	$22,346	$25,046

Investment_In_BBEP_Narrative_D

Investment In BBEP (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011	Sep. 30, 2011
				BBEP [Member]	BBEP [Member]
Business Acquisition [Line Items]	'	'	'	'	'
Gain on sale and disposition of BBEP units	$0	$0	$217,893,000	$217,900,000	'
Weighted Average Carrying Value	'	'	'	$3.51	'
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	-3,904,000	-57,826,000	51,780,000	'	24,000,000
Unrealized gains on interest rate swaps	'	'	'	'	$3,300,000

Investment_In_BBEP_Operations_

Investment In BBEP (Operations Statement) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2011

BBEP [Member]

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Revenue

$114,246

$153,116

$175,497

$118,703

$223,966

$118,188

$194,018

$172,866

$561,562

$709,038

$943,623

$425,386

[1]

Operating expense

'

'

'

'

'

'

'

'

436,246

3,215,896

821,019

313,388

Operating income (loss)

13,575

[2]

60,049

[3]

394,894

[4]

-3,874

-468,213

[5]

-576,551

[6]

-1,153,012

[7]

-267,985

[8]

464,644

-2,465,761

122,604

111,998

Interest and other

'

'

'

'

'

'

'

'

'

'

'

40,759

[9]

Income tax (benefit) expense

'

'

'

'

'

'

'

'

14,550

-295,570

57,863

1,070

Noncontrolling interests

'

'

'

'

'

'

'

'

'

'

'

183

Net income (loss) attributable to Quicksilver

($31,775)

$10,577

$242,523

($59,707)

($548,499)

[5]

($790,520)

[6]

($802,022)

($211,565)

$161,618

($2,352,606)

$90,046

$69,986

[1]

For the twelve months ended SeptemberB 30, 2011, unrealized gains of $24.0 million on commodity derivatives were recognized.

[2]

Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

[3]

Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR

[4]

Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

[5]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[6]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[7]

Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

[8]

Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

[9]

The twelve months ended SeptemberB 30, 2011 included $3.3 million for unrealized gains on interest rate swaps.

Property_Plant_And_Equipment_N

Property, Plant And Equipment (Narrative) (Details) (USD $)	3 Months Ended				12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Percentage drop in Henry Hub price	'	'	'	'	'	33.00%	'
Percentage decrease related to NGL prices	'	'	'	'	'	28.00%	'
Percentage decrease of AECO stated price	'	'	'	'	'	36.00%	12.00%
Impairment expense	'	'	'	'	$1,863,000	$2,625,928,000	$107,059,000
Capitalized overhead costs related to exploration and development activities	'	'	'	'	13,600,000	16,800,000	18,300,000
Depletion per Mcfe	'	'	'	'	'	'	1.35
Depreciation Expense	'	'	'	'	17,100,000	18,600,000	20,300,000
Midstream Assets Texas [Member]	'	'	'	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Additional impairment charges	'	'	'	'	'	'	58,000,000
Horn River Asset [Member] | Minimum [Member]	'	'	'	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Estimated years for evaluation of acquisition costs	'	'	'	'	'9 years	'	'
U.S. [Member]	'	'	'	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Impairment expense	451,500,000	479,900,000	1,042,700,000	178,000,000	1,809,000	2,152,665,000	0
Depletion per Mcfe	'	'	'	'	0.51	1.14	'
West Texas [Member] | Minimum [Member]	'	'	'	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Estimated years for evaluation of acquisition costs	'	'	'	'	'3 years	'	'
Canada [Member]	'	'	'	'	'	'	'
Property, Plant and Equipment [Line Items]	'	'	'	'	'	'	'
Impairment expense	102,800,000	66,300,000	157,000,000	139,900,000	0	465,935,000	49,063,000
Depletion per Mcfe	'	'	'	'	$0.14	$0.83	'

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment [Abstract]	'	'
Subject to depletion	$5,687,557	$5,770,913
Unevaluated costs of oil and gas properties	221,605	307,267
Accumulated depletion	-5,268,719	-5,297,220
Net oil and gas properties	640,443	780,960
Pipelines and processing facilities	347,093	375,248
General properties	72,125	75,147
Accumulated depreciation	-198,856	-202,297
Property, Plant and Equipment, Other, Net	220,362	248,098
Property, plant and equipment - net	$860,805	$1,029,058

Property_Plant_And_Equipment_S1

Property, Plant And Equipment (Schedule Of Charges For Impairment) (Details) (USD $)	3 Months Ended				12 Months Ended
	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Impairment expense	'	'	'	'	$1,863,000	$2,625,928,000	$107,059,000
U.S. [Member]	'	'	'	'	'	'	'
Impairment expense	451,500,000	479,900,000	1,042,700,000	178,000,000	1,809,000	2,152,665,000	0
Canada [Member]	'	'	'	'	'	'	'
Impairment expense	102,800,000	66,300,000	157,000,000	139,900,000	0	465,935,000	49,063,000
Oil and Gas Properties [Member] | U.S. [Member]	'	'	'	'	'	'	'
Impairment expense	'	'	'	'	0	2,152,128,000	0
Oil and Gas Properties [Member] | Canada [Member]	'	'	'	'	'	'	'
Impairment expense	'	'	'	'	0	465,935,000	49,063,000
Midstream Operations [Member] | Other Property and Equipment [Member] | U.S. [Member]	'	'	'	'	'	'	'
Impairment expense	'	'	'	'	54,000	7,328,000	57,996,000
Exploration and Production Equipment [Member] | Other Property and Equipment [Member] | U.S. [Member]	'	'	'	'	'	'	'
Impairment expense	'	'	'	'	$1,809,000	$537,000	$0

Property_Plant_And_Equipment_S2

Property, Plant And Equipment (Schedule Of Unevaluated Natural Gas And Oil Properties Not Subject To Depletion) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]	'	'
Total	$221,605	$307,267
Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Total	12,098	53,098
Before Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Total	42,177	90,997
Before Previous Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Total	59,398	23,420
Prior [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Total	107,932	139,752
U.S. [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	16,497	83,059
Exploration costs	378	2,883
Capitalized interest	2,467	4,093
Total	19,342	90,035
U.S. [Member] | Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	0	6,844
Exploration costs	14	2,676
Capitalized interest	1,093	4,093
Total	1,107	13,613
U.S. [Member] | Before Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	3,013	42,339
Exploration costs	364	207
Capitalized interest	1,374	0
Total	4,751	42,546
U.S. [Member] | Before Previous Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	13,484	1,447
Exploration costs	0	0
Capitalized interest	0	0
Total	13,484	1,447
U.S. [Member] | Prior [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	0	32,429
Exploration costs	0	0
Capitalized interest	0	0
Total	0	32,429
Canada [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	72,842	81,464
Exploration costs	110,295	119,864
Capitalized interest	19,126	15,904
Total	202,263	217,232
Canada [Member] | Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	0	333
Exploration costs	7,044	36,356
Capitalized interest	3,947	2,796
Total	10,991	39,485
Canada [Member] | Before Current Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	2,956	0
Exploration costs	31,746	44,837
Capitalized interest	2,724	3,614
Total	37,426	48,451
Canada [Member] | Before Previous Year [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	1,300	643
Exploration costs	41,092	18,500
Capitalized interest	3,522	2,830
Total	45,914	21,973
Canada [Member] | Prior [Member]	'	'
Property, Plant and Equipment [Line Items]	'	'
Acquisition costs	68,586	80,488
Exploration costs	30,413	20,171
Capitalized interest	8,933	6,664
Total	$107,932	$107,323

Property_Plant_And_Equipment_S3

Property, Plant And Equipment (Schedule Of Unevaluated Property Costs) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Total	$221,605	$307,267
Barnett Shale [Member]	'	'
Total	0	40,716
West Texas [Member]	'	'
Total	19,343	49,318
Horn River Asset [Member]	'	'
Total	$202,262	$217,233

Other_Assets_Schedule_Of_Other

Other Assets (Schedule Of Other Assets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Other Assets, Noncurrent Disclosure [Abstract]	'	'
Deferred financing costs	$84,951	$59,059
Less accumulated amortization	-50,171	-27,335
Net deferred financing costs	34,780	31,724
Notes receivable	6,464	7,385
Other	360	838
Other assets, total	$41,604	$39,947

Accrued_Liabilities_Schedule_O

Accrued Liabilities (Schedule Of Accrued Liabilities) (Details) New (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accrued Liabilities [Abstract]	'	'
Interest payable	$38,260	$67,116
Accrued operating expenses	37,747	38,733
Prepayments from partners	425	0
Revenue payable	22,589	21,013
Accrued state income and franchise taxes	1,080	1,183
Accrued production and property taxes	870	609
Environmental liabilities	36	122
Accrued product purchases	270	336
Current asset retirement obligations	433	577
Other	1,140	971
Accrued liabilities, total	$102,850	$130,660

LongTerm_Debt_Narrative_Detail

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

3 Months Ended

6 Months Ended

12 Months Ended

3 Months Ended

1 Months Ended

2 Months Ended

3 Months Ended

12 Months Ended

1 Months Ended

2 Months Ended

3 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

12 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

12 Months Ended

6 Months Ended

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2008

Aug. 21, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2009

Aug. 21, 2013

Jun. 30, 2009

Jun. 30, 2013

Aug. 31, 2009

Jun. 30, 2013

Sep. 30, 2009

Jun. 30, 2013

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Jun. 30, 2013

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan [Member]

Combined Credit Agreements [Member]

Combined Credit Agreements [Member]

Canadian Credit Facility [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2015 [Member]

Combined Credit Agreements [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due Two Thousand Twenty-one [Member]

Senior Subordinated Notes Due 2016 [Member]

Maximum [Member]

Maximum [Member]

Minimum [Member]

Minimum [Member]

Multiple Subsidiaries Set One [Member]

Multiple Subsidiaries Set Two [Member]

CDOR Rate [Member]

CDOR Rate [Member]

LIBOR [Member]

LIBOR [Member]

LIBOR [Member]

LIBOR [Member]

Canadian Prime Rate [Member]

Canadian Prime Rate [Member]

U S Prime Rate [Member]

U S Prime Rate [Member]

Alternative Base Rate [Member]

London Interbank Offered Rate (LIBOR) [Member]

London Interbank Offered Rate (LIBOR) [Member]

Rate

Rate

Rate

Rate

Rate

Rate

Rate

Rate

U S Credit Facility [Member]

Global Letter Of Credit [Member]

Combined Credit Agreements [Member]

U S Credit Facility [Member]

U S Credit Facility [Member]

Maximum [Member]

Minimum [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Senior Secured Second Lien Term Loan [Member]

U S Credit Facility [Member]

Senior Secured Second Lien Term Loan [Member]

Rate

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Premium and Tender Premium Paid

$51,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement

'

'

'

'

'

'

100,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

'

100.00%

'

'

'

'

'

'

'

100.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

100.00%

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Basis Spread on Variable Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.75%

'

'

'

'

'

3.75%

2.75%

'

5.75%

3.75%

2.75%

2.75%

1.75%

2.75%

1.75%

4.75%

1.00%

5.75%

Borrowing capacity

'

'

'

'

'

'

'

'

350,000,000

850,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

280,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Permitted second lien debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

825,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Available borrowing under combined credit agreements

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

97,600,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Increase in applicable margin

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum Mortgage Properties Requirement

'

'

'

'

'

80.00%

'

'

'

'

'

'

'

'

'

'

'

87.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior secured debt leverage ratio

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Line of credit facility borrowing base utilization percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

75.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal amount

'

'

'

'

'

'

'

'

'

'

'

'

'

475,000,000

'

'

'

'

600,000,000

'

'

'

300,000,000

'

'

'

350,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Interest Rate, Stated Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

8.25%

'

'

'

'

11.75%

'

11.75%

'

9.13%

'

'

11.00%

7.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Covenant, EBITDA to Interest Expense

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2.25

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Consent Fee

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

11,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Unamortized Discount

'

'

'

'

'

'

17,428,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Expense

'

'

251,847,000

164,051,000

186,024,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Costs Capitalized

'

'

-7,700,000

-18,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Payments of Financing Costs

'

23,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Issuance Cost

4,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Face Amount

'

'

'

'

'

'

'

'

'

'

'

625,000,000

200,000,000

'

'

'

438,000,000

'

'

'

'

590,600,000

'

'

'

325,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Long-term Debt

'

'

1,308,382,000

310,430,000

843,108,000

'

'

'

'

'

'

'

'

'

450,700,000

2,300,000

'

'

'

654,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Issue Percentage

'

'

'

'

'

'

'

'

'

'

'

97.00%

97.00%

98.66%

'

'

'

'

96.72%

'

96.72%

'

97.61%

'

'

94.93%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Issuance of debt

'

'

1,237,352,000

467,959,000

855,822,000

'

'

'

'

'

'

606,300,000

194,000,000

'

'

'

'

'

'

'

580,300,000

'

'

'

292,800,000

308,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Floor on Debt Rate

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.25%

1.25%

'

'

'

'

'

'

2.25%

'

'

Long Term Debt Repurchase Price

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,027.90

'

'

'

'

1,068

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest Paid on Repurchased Debt

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

32.08

'

'

'

'

55.49

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Repurchase Amount

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1,000

'

'

'

'

1,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Amount Tendered

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$425,200,000

'

'

'

'

$582,500,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

LongTerm_Debt_Schedule_Of_Long

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
Debt Instrument [Line Items]	'	'
Combined Credit Agreements	$41,200,000	'
Long-term Debt	1,984,144,000	2,046,418,000
Unamortized deferred gain - terminated interest rate swaps	4,802,000	16,788,000
Long-term debt	1,988,946,000	2,063,206,000
Combined Credit Agreements [Member]	'	'
Debt Instrument [Line Items]	'	'
Combined Credit Agreements	211,200,000	388,150,000
Senior Notes Due 2015 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior notes	10,472,000	435,851,000
Debt Instrument, Unamortized Discount	30,000	2,149,000
Senior Notes Due 2016 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior notes	8,044,000	579,795,000
Debt Instrument, Unamortized Discount	105,000	10,825,000
Senior Notes Due 2019 [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior notes	293,243,000	292,622,000
Debt Instrument, Unamortized Discount	4,757,000	5,378,000
Senior Notes Due Two Thousand Twenty-one [Member]	'	'
Debt Instrument [Line Items]	'	'
Senior notes	309,190,000	0
Debt Instrument, Unamortized Discount	15,810,000	0
Senior Subordinated Notes [Member]	'	'
Debt Instrument [Line Items]	'	'
Subordinated Long-term Debt, Noncurrent	350,000,000	350,000,000
Senior Secured Second Lien Term Loan [Member]	'	'
Debt Instrument [Line Items]	'	'
Secured Long-term Debt, Noncurrent	607,572,000	0
Debt Instrument, Unamortized Discount	17,428,000	0
Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement	100,000,000	'
Senior Secured Second Lien Term Loan Due 2019 [Member]	'	'
Debt Instrument [Line Items]	'	'
Secured Long-term Debt, Noncurrent	194,423,000	0
Debt Instrument, Unamortized Discount	5,577,000	0
Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement	$100,000,000	'

LongTerm_Debt_LongTerm_Debt_Sc

Long-Term Debt Long-Term Debt (Schedule Of Maturities Of Long-Term Debt) (Details) (USD $)	Dec. 31, 2013
In Thousands, unless otherwise specified
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$0
Long-term Debt, Maturities, Repayments of Principal in Year Two	10,502
Long-term Debt, Maturities, Repayments of Principal in Year Three	569,349
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	1,448,000
Combined Credit Agreements [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	211,200
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
Senior Secured Second Lien Term Loan Due 2019 [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	200,000
Senior Secured Second Lien Term Loan [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	625,000
Senior Notes Due 2015 [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	10,502
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
Senior Notes Due 2016 [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	8,149
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
Senior Notes Due 2019 [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	298,000
Senior Notes Due Two Thousand Twenty-one [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	0
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	325,000
Senior Subordinated Notes Due 2016 [Member]	'
Debt Instrument [Line Items]	'
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	0
Long-term Debt, Maturities, Repayments of Principal in Year Two	0
Long-term Debt, Maturities, Repayments of Principal in Year Three	350,000
Long-term Debt, Maturities, Repayments of Principal in Year Four	0
Long-term Debt, Maturities, Repayments of Principal in Year Five	0
Long-term Debt, Maturities, Repayments of Principal after Year Five	$0

LongTerm_Debt_Schedule_Of_Outs

Long-Term Debt (Schedule Of Outstanding Debt) (Details) (USD $)

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Mar. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

In Millions, unless otherwise specified

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Canadian Credit Facility [Member]

Combined Credit Agreements [Member]

Combined Credit Agreements [Member]

Multiple Subsidiaries Set One [Member]

Multiple Subsidiaries Set Two [Member]

Maximum [Member]

Senior Subordinated Notes [Member]

First Mortgage [Member]

Second Mortgage [Member]

Second Mortgage [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

CDOR Rate [Member]

CDOR Rate [Member]

London Interbank Offered Rate (LIBOR) [Member]

LIBOR [Member]

LIBOR [Member]

LIBOR [Member]

LIBOR [Member]

Canadian Prime Rate [Member]

Canadian Prime Rate [Member]

U.S. Prime Rate [Member]

U.S. Prime Rate [Member]

ABR [Member]

2013 [Member]

2013 [Member]

2013 [Member]

2014 [Member]

2014 [Member]

2014 [Member]

2014 [Member]

2014 [Member]

2015 [Member]

2015 [Member]

2015 [Member]

2015 [Member]

Year Twenty Sixteen [Member]

Year Twenty Seventeen [Member]

Year Twenty Nineteen [Member]

Year Twenty Twenty [Member]

Combined Credit Agreements [Member]

Combined Credit Agreements [Member]

U.S. Credit Facility [Member]

U.S. Credit Facility [Member]

U.S. Credit Facility [Member]

Rate

Combined Credit Agreements [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Senior Notes Due Two Thousand Twenty-one [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2019 [Member]

Maximum [Member]

Minimum [Member]

U.S. Credit Facility [Member]

Maximum [Member]

Minimum [Member]

Second Mortgage [Member]

Second Mortgage [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Minimum [Member]

Second Mortgage [Member]

Senior Subordinated Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Subordinated Notes [Member]

Second Mortgage [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Second Mortgage [Member]

Second Mortgage [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Senior Notes [Member]

Maximum [Member]

Rate

Rate

Rate

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Canadian Credit Facility [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2016 [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Senior Notes Due 2015 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2019 [Member]

Senior Secured Second Lien Term Loan [Member]

Senior Secured Second Lien Term Loan Due 2019 [Member]

Senior Notes Due 2016 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due 2019 [Member]

Senior Notes Due Two Thousand Twenty-one [Member]

Senior Notes Due Two Thousand Twenty-one [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Debt Instrument, Reference Rate, Floor

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.25%

'

'

'

'

'

2.25%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Current ratio

'

'

'

'

'

'

'

'

'

'

1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Minimum EBITDA to cash interest expense ratio

'

'

'

'

'

'

'

'

'

'

1.1

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Senior secured debt leverage ratio

'

'

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

2

'

Line of Credit Facility, Current Borrowing Capacity

'

'

'

'

$350

$850

'

'

'

'

$350

[1],[2]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Principal amount

'

'

'

'

'

'

'

'

'

350

'

625

200

325

[1]

11

[1]

8

[1]

298

[1]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Scheduled maturity date

'

'

'

'

'

'

'

'

'

1-Apr-16

6-Sep-16

[3]

21-Jun-19

[3]

21-Jun-19

[3]

1-Jul-21

1-Aug-15

1-Jan-16

15-Aug-19

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Interest rate on outstanding borrowings at June 30, 2012

'

'

'

'

'

'

'

'

'

7.13%

3.95%

[3]

7.00%

7.00%

11.00%

8.25%

11.75%

9.13%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Base interest rate options

'

'

'

'

'

'

'

'

'

'N/A

'LIBOR, ABR, CDOR

[4],[5]

'LIBOR floor of 1.25%; ABR floor of 2.25%

'LIBOR floor of 1.25%

'N/A

'N/A

'N/A

'N/A

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Financial covenants

'

'

'

'

'

'

'

'

'

'N/A

'- Minimum current ratio of 1.0 - Minimum EBITDA to cash interest expense ratio of 1.10 - Maximum senior secured debt leverage ratio of 2.0

[6]

'N/A

'N/A

'N/A

'N/A

'N/A

'N/A

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Significant restrictive covenants

'

'

'

'

'

'

'

'

'

'- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions

'- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments

[6]

'- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions

'- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions

[6]

'- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions

'- Asset sales

[6]

'- Asset sales

[6]

'- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions

[6]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Optional redemption

'

'

'

'

'

'

'

'

'

'April 1, 2013: 101.188 2014: par

'Any time

[6]

'Any time, subject to re-pricing event June 21, 2014: 102 2015: 101

'Any time, subject to re-pricing event June 21, 2014: 102 2015: 101

'July 1, 2019: 102.000 2020: par

'August 1, 2013: 101.938 2014: par

[6]

'July 1, 2013: 105.875 2014: 102.938 2015: par

[6]

'August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Make-whole redemption

'

'

'

'

'

'

'

'

'

'N/A

'N/A

'N/A

'N/A

'Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps

[6]

'N/A

'N/A

'Callable prior to August 15, 2014 at make-whole call price of Treasury +50 bps

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity Clawback

'

'

'

'

'

'

'

'

'

'N/A

'N/A

'N/A

'N/A

'Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%

[6]

'N/A

'N/A

'N/A

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Change of control

'

'

'

'

'

'

'

'

'

'Put at 101% of principal plus accrued interest

[6]

'Event of default

[6]

'Put at 101% of principal plus accrued interest

[6]

'Put at 101% of principal plus accrued interest

'Put at 101% of principal plus accrued interest

'Put at 101% of principal plus accrued interest

[6]

'Put at 101% of principal plus accrued interest

[6]

'Put at 101% of principal plus accrued interest

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Estimated fair value

'

'

'

'

'

'

'

'

'

341.3

[7]

211.2

625

200

354.3

[7]

10.6

[7]

7.8

[7]

298

[7]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Equity interests

100.00%

'

'

100.00%

'

'

100.00%

65.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement

'

$100

$100

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Commitment fee percentage

'

'

'

'

'

'

'

'

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

0.50%

Redemption percentage of par value

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

1.25%

'

'

'

'

'

101.19%

'

105.88%

100.00%

102.00%

100.00%

102.94%

104.56%

101.00%

'

100.00%

103.04%

101.52%

100.00%

102.00%

100.00%

'

'

Applicable margin in addition to interest rate

'

'

'

'

'

'

'

'

2.75%

'

'

'

'

'

'

'

'

3.75%

2.75%

1.00%

3.75%

2.75%

'

'

2.75%

1.75%

2.75%

1.75%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Make-whole redemption treasury plus percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

0.50%

'

'

0.50%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of principal plus accrued interest for change of control

'

'

'

'

'

'

'

'

'

101.00%

'

101.00%

101.00%

101.00%

101.00%

101.00%

101.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

101.94%

'

'

'

'

'

'

'

101.00%

'

'

'

'

'

'

'

'

Equity Clawback Redemption Percentage

'

'

'

'

'

'

'

'

'

'

'

'

'

111.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Borrowings under the Amended and Restated U.S. Credit Facility, Second Lien Term Loan and Second Lien Notes due 2019 are guaranteed by certain of Quicksilverbs domestic subsidiaries and are secured (on a first priority basis with respect to the Amended and Restated U.S. Credit Facility and on a second priority basis with respect to the Second Lien Term Loan and the Second Lien Notes due 2019) by 100% of the equity interests of each of Cowtown Pipeline Management, Inc., Cowtown Pipeline Funding, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Barnett Shale Operating LLC, Silver Stream Pipeline Company LLC, QPP Parent LLC and QPP Holdings LLC (collectively, the bDomestic Pledged Equityb), 65% of the equity interests of Quicksilver Resources Canada Inc. (bQuicksilver Canadab) and Quicksilver Production Partners Operating Ltd. (with respect to the Amended and Restated U.S. Credit Facility, on a ratable basis with borrowings under the Amended and Restated Canadian Credit Facility) and the majority of Quicksilver's domestic proved oil and gas properties and related assets, (the bDomestic Pledged Propertyb).B Borrowings under the Amended and Restated Canadian Credit Facility are guaranteed by Quicksilver and certain of its domestic subsidiaries and are secured by the Domestic Pledged Equity, the Domestic Pledged Property, 100% of the equity interests of Quicksilver Canada (65% of which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and any Canadian restricted subsidiaries, under the Amended and Restated Canadian Credit Facility, and 65% of the equity interests of Quicksilver Production Partners Operating Ltd. (which is on a ratable basis with the borrowings under the Amended and Restated U.S. Credit Facility) and the majority of Quicksilver Canada's oil and gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.

[2]

The principal amount for the Combined Credit Agreements represents the global borrowing base as of DecemberB 31, 2013.

[3]

The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes, the 2016 Senior Subordinated Notes, the Second Lien Term Loan or the Second Lien Notes due 2019, if on the applicable date any amount of such debt remains outstanding. The Second Lien Term Loan and Second Lien Notes due 2019 are required to be repaid (1) 91 days prior to the maturity of the 2019 Senior Notes if more than $100 million of the 2019 Senior Notes remain outstanding and (2) 91 days prior to the maturity of the 2015 Senior Notes, the 2016 Senior Notes or the 2016 Senior Subordinated Notes if on the applicable date the aggregate amount of all such notes remaining outstanding is greater than $100 million.

[4]

Amounts outstanding under the Amended and Restated U.S. Credit Facility bear interest, at our election, at (i) adjusted LIBOR (as defined in the Amended and Restated U.S. Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii)B ABR (as defined in the Amended and Restated U.S. Credit Facility), which is the greatest of (a)B the prime rate announced by JPMorgan, (b)B the federal funds rate plus 0.50% and (c)B adjusted LIBOR for an interest period of one month plus 1.00%, plus, in each case under scenario, (ii) an applicable margin between 1.75% and 2.75%. We also pay a per annum fee on the LC Exposure (as defined in the Amended and Restated U.S. Credit Facility) of all letters of credit issued under the Amended and Restated U.S. Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated U.S. Credit Facility of 0.50%.

[5]

Amounts outstanding under the Amended and Restated Canadian Credit Facility bear interest, at our election, at (i)B the CDOR Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%, (ii)B the Canadian Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75%, (iii)B the U.S. Prime Rate (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 1.75% and 2.75% and (iv)B adjusted LIBOR (as defined in the Amended and Restated Canadian Credit Facility) plus an applicable margin between 2.75% and 3.75%. We pay a per annum fee on the LC Exposure (as defined in the Amended and Restated Canadian Credit Facility) of all letters of credit issued under the Amended and Restated Canadian Credit Facility equal to the applicable margin, with respect to Eurodollar loans, and a commitment fee on the unused availability under the Amended and Restated Canadian Credit Facility of 0.50%.

[6]

The information presented in this table is qualified in all respects by reference to the full text of the covenants, provisions and related definitions contained in the documents governing the various components of our debt.

[7]

The estimated fair value is determined using market quotations based on recent trade activity for fixed rate obligations (bLevel 2b inputs). Our Second Lien Term Loan and Second Lien Notes due 2019 feature variable interest rates and we estimate their fair value by using market quotations based on recent trade activity (bLevel 3b input). We consider our Combined Credit Agreements which have a variable interest rate to have a fair value equal to their carrying value (bLevel 1b input).

LongTerm_Debt_LongTerm_Debt_Mi

Long-Term Debt Long-Term Debt (Minimum Required Interest Coverage Ratio) (Details) (Details) (Minimum [Member], Combined Credit Agreements [Member])	12 Months Ended
	Dec. 31, 2013
Fourth Quarter Two Thousand Thirteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
First Quarter Two Thousand Fourteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
Second Quarter Two Thousand Fourteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
Third Quarter Two Thousand Fourteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
Fourth Quarter Two Thousand Fourteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
First Quarter Two Thousand Fifteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.1
Second Quarter Two Thousand Fifteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.15
Third Quarter Two Thousand Fifteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.15
Fourth Quarter Two Thousand Fifteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.2
First Quarter Two Thousand Sixteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	1.5
Second Quarter Two Thousand Sixteen [Member]	'
Debt Instrument [Line Items]	'
Interest coverage ratio	2

Asset_Retirement_Obligations_E

Asset Retirement Obligations (Estimated Asset Retirement Obligation Activity) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Asset Retirement Obligation [Abstract]	'	'
Beginning asset retirement obligations	$116,526	$85,822
Additional liability incurred	3,922	4,072
Change in estimates	-7,582	-21,080
Accretion expense	5,109	4,122
Asset retirement costs incurred	1,560	1,846
Gain on settlement of liability	-742	-2,229
Asset Retirement Obligations, Dispositions	-21,935	0
Currency translation adjustment	-3,697	-1,047
Ending asset retirement obligations	106,689	116,526
Less current portion	-433	-577
Long-term asset retirement obligation	$106,256	$115,949

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
		Rate	Rate	Rate
Federal statutory income tax rate	'	35.00%	'	'
State Statutory Rate	'	1.00%	1.00%	1.00%
Remaining net operating tax losses	$340,000,000	$525,000,000	$340,000,000	'
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	55,814,000	47,883,000	55,814,000	'
Net Operating Loss, change in	'	185,000,000	'	'
Tax Valuation Allowance Expense, State	'	3,680,000	0	0
U.S. federal valuation allowance expense	'	-186,713,000	533,974,000	0
Canadian valuation allowance expense	'	1,647,000	61,325,000	0
Tax basis in fortune creek, net	'	29,000,000	'	'
Effective Income Tax Rate Reconciliation, Foreign Income Tax Rate Differential, Percent	'	-0.26%	-1.93%	2.41%
Valuation Allowance, Amount	598,980,000	417,595,000	598,980,000	3,700,000
Tax benefits recognized	9,200,000	0	9,219,000	'
Canada [Member]	'	'	'	'
Foreign Statutory Rate, Canada	'	25.20%	25.00%	25.00%
Valuation Allowance, Deferred Tax Asset, Change in Amount	'	-1,600,000	'	'
UNITED STATES	'	'	'	'
Valuation Allowance, Deferred Tax Asset, Change in Amount	'	$187,000,000	'	'
Canada [Member]	'	'	'	'
Effective Income Tax Rate Reconciliation, Foreign Income Tax Rate Differential, Percent	'	12.50%	'	'
Minimum [Member]	'	'	'	'
Net operating tax losses period	'	31-Dec-29	'	'
Maximum [Member]	'	'	'	'
Net operating tax losses period	'	31-Dec-33	'	'

Income_Taxes_Components_Of_Def

Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Components of Deferred Tax Assets and Liabilities [Abstract]	'	'	'
Property, plant and equipment	$209,134	$483,771	'
Net operating loss carry-forwards	183,982	109,100	'
Investment in Fortune Creek	3,763	3,763	'
AMT tax credit	47,883	55,814	'
Settlements of interest rate swaps	1,681	5,876	'
Deferred compensation expense	11,711	11,141	'
Deferred Tax Assets, State Taxes	3,680	0	'
Other	791	2,710	'
Deferred tax assets	462,625	672,175	'
Gains from hedging and derivative activities	-44,039	-73,195	'
Deferred Tax Liabilities, Other	-991	0	'
Deferred tax liabilities	-45,030	-73,195	'
Net deferred tax asset (liability)	417,595	598,980	'
Valuation allowance	-417,595	-598,980	-3,700
Current deferred income tax liability	0	0	'
Non-current deferred income tax liability	0	0	'
Total deferred tax asset (liability)	$0	$0	'

Income_Taxes_Components_Of_Inc

Income Taxes (Components Of Income Tax Expense) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (loss) before income taxes	$176,168	($2,648,176)	$147,909
UNITED STATES	'	'	'
Income (Loss) from Continuing Operations before Income Taxes, Domestic	184,034	-2,142,730	146,090
Income (loss) before income taxes	129,544	-1,955,773	240,658
Canada [Member]	'	'	'
Income (Loss) from Continuing Operations before Income Taxes, Foreign	-7,866	-505,446	1,819
Income (loss) before income taxes	$45,690	($459,288)	($14,559)

Income_Taxes_Income_Taxes_Comp

Income Taxes Income Taxes (Components Of Income Tax Expense 1) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Taxes [Abstract]	'	'	'
Current state income tax expense (benefit)	$900	$1,752	($1,706)
Current U.S. federal income tax expense (benefit)	-7,931	0	-5,565
Current Canadian income tax expense	0	0	642
Total current income tax expense (benefit)	-7,031	1,752	-6,629
Deferred state income tax expense (benefit)	-3,680	0	1,980
Tax Valuation Allowance Expense, State	3,680	0	0
Deferred U.S. federal income tax expense (benefit)	205,820	-763,639	58,890
U.S. federal valuation allowance expense	-186,713	533,974	0
Deferred Canadian income tax expense (benefit)	827	-128,982	3,622
Canadian valuation allowance expense	1,647	61,325	0
Total deferred income tax expense (benefit)	21,581	-297,322	64,492
Total income tax expense (benefit)	$14,550	($295,570)	$57,863

Income_Taxes_Statutory_Federal

Income Taxes (Statutory Federal Income Tax Rate) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011
	Rate	Rate			Rate
Components of Deferred Tax Assets and Liabilities [Abstract]	'	'	'	'	'
U.S. federal statutory tax rate	35.00%	35.00%	35.00%	35.00%	35.00%
Permanent differences	4.80%	-0.06%	-0.06%	1.51%	1.51%
State income taxes net of federal deduction	0.31%	-0.04%	-0.04%	0.12%	0.12%
Canadian income taxes	-0.26%	-1.93%	-1.93%	2.41%	2.41%
Other	-0.15%	0.67%	0.67%	0.08%	0.08%
Derivatives deferred in OCI	12.43%	0.00%	0.00%	0.00%	0.00%
Valuation allowance	-43.87%	-22.48%	-22.48%	0.00%	0.00%
Effective income tax rate	8.26%	11.16%	11.16%	39.12%	39.12%

Income_Taxes_Income_Taxes_Unre

Income Taxes Income Taxes (Unrecognized Tax Benefits) (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]	'	'	'
Unrecognized tax benefit, beginning of period	'	$0	$9,219
Changes	-9,200	0	-9,219
Unrecognized tax benefits, end of period	$0	$0	$0

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]	'	'	'
Other Nonoperating Income (Expense)	($17,384,000)	$1,108,000	$219,768,000
Surety bonds	6,600,000	'	'
Outstanding letters of credit	41,200,000	'	'
Accrual for Environmental Loss Contingencies	36,000	122,000	'
Ngtl [Member]	'	'	'
Loss Contingencies [Line Items]	'	'	'
Other Nonoperating Income (Expense)	12,800,000	'	'
Tarrant County, Texas [Member]	'	'	'
Loss Contingencies [Line Items]	'	'	'
Litigation Settlement, Expense	$3,300,000	'	'

Commitments_And_Contingencies_2

Commitments And Contingencies (Summary Of Contractual Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Contractual Obligations [Line Items]	'		'	'
GPT Contracts, 2014	$86,628,000	[1]	'	'
GPT Contracts, 2015	85,043,000	[1]	'	'
GPT Contracts, 2016	81,803,000	[1]	'	'
GPT Contracts, 2017	78,326,000	[1]	'	'
GPT Contracts, 2018	65,860,000	[1]	'	'
GPT Contracts, Thereafter	140,624,000	[1]	'	'
GPT Contracts, Total	538,284,000	[1]	'	'
Drilling Rig Contracts, 2014	4,240,000	[2]	'	'
Drilling Rig Contracts, 2015	0	[2]	'	'
Drilling Rig Contracts, 2016	0	[2]	'	'
Drilling Rig Contracts, 2017	0	[2]	'	'
Drilling Rig Contracts, 2018	0	[2]	'	'
Drilling Rig Contracts, Thereafter	0	[2]	'	'
Drilling Rig Contracts, Total	4,240,000	[2]	'	'
Operating Leases, 2012	3,912,000	[3]	'	'
Operating Leases, 2013	3,994,000	[3]	'	'
Operating Leases, 2014	4,123,000	[3]	'	'
Operating Leases, 2015	4,070,000	[3]	'	'
Operating Leases, 2016	4,043,000	[3]	'	'
Operating Leases, Thereafter	12,996,000	[3]	'	'
Operating Leases, Total	33,138,000	[3]	'	'
Purchase Obligations, 2014	3,071,000	[4]	'	'
Purchase Obligations, 2015	220,000	[4]	'	'
Purchase Obligations, 2016	0	[4]	'	'
Purchase Obligations, 2017	0	[4]	'	'
Purchase Obligations, 2018	0	[4]	'	'
Purchase Obligations, Thereafter	0	[4]	'	'
Purchase Obligations, Total	3,291,000	[4]	'	'
Rent expense for operating leases	3,600,000		4,200,000	4,800,000
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals	2,200,000		'	'
Maximum [Member]	'		'	'
Contractual Obligations [Line Items]	'		'	'
Drilling rig contracts outstanding payment	$20,000		'	'
[1]	Under contracts with various third parties, we are obligated to provide minimum daily natural gas volume for gathering, processing, fractionation and transportation, as determined on a monthly basis, or pay for any deficiencies at a specified reservation fee rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts.
[2]	We lease drilling rigs from third parties for use in our development and exploration programs. The outstanding drilling rig contract requires payment of a specified day rate of $20,000 for the entire lease term regardless of our utilization of the drilling rigs.
[3]	We lease office buildings and other property under operating leases. Rent expense for operating leases with terms exceeding one month was $3.6 million in 2013, $4.2 million in 2012 and $4.8 million in 2011. Minimum payments have not been reduced by minimum sublease rentals of $2.2 million due in the future under noncancelable subleases.
[4]	At DecemberB 31, 2013, we were under contract to purchase goods and services for use in field and gas plant operations.

Fortune_Creek_Details

Fortune Creek (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013
	USD ($)	CAD	KKR [Member]
	acre		USD ($)
			in
			mi
			Y
Area of business, acres	30,000,000	30,000,000	'
Length of gathering line contributed to partnership, miles	'	'	20
Diameter of gathering line contributed to partnership, inches	'	'	20
Minimum expenditures required for drilling and completion activities	'	'	$300,000,000
Capital expenditures incurred	'	'	180,000,000
Capital Contribution, Fortune Creek	'	28,000,000	'
Reduction in Gathering Rate, Fortune Creek	0.13	'	'
Dedicated years for gas production	'	'	10
Payments to acquire interest in joint venture	'	'	$125,000,000
Percentage of interest by parent in the partnership	'	'	50.00%

Quicksilver_Stockholders_Equit2

Quicksilver Stockholders' Equity (Narrative) (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

12 Months Ended

3 Months Ended

6 Months Ended

15-May-13

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

31-May-09

Jan. 31, 2008

Dec. 31, 2006

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Feb. 15, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2013

Restricted Stock [Member]

Restricted Stock [Member]

Restricted Stock [Member]

Stock Option [Member]

Stock Option [Member]

Stock Option [Member]

Affiliated Entity [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Translation Adjustment [Member]

Accumulated Translation Adjustment [Member]

compensation expense correction [Domain]

compensation expense correction [Domain]

compensation expense correction [Domain]

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

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, shares authorized

'

400,000,000

'

400,000,000

400,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Common stock, par value

'

$0.01

'

$0.01

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred Stock, Redemption Price Per Share

'

'

'

'

'

'

$10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, shares authorized

'

10,000,000

'

10,000,000

10,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Preferred stock, par value

'

$0.01

'

$0.01

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Shares of common stock outstanding

'

177,300,000

'

177,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total intrinsic values of options

'

'

'

'

'

'

'

'

'

'

'

6,300,000

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

'

'

'

'

'

'

'

'

'

'

'

$8.24

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term

'

'

'

'

'

'

'

'

'

'

'

'6 years 61 days

'

'

'

'

'

'

'

'

'

'

Unrecognized compensation cost related to outstanding unvested awards

'

'

'

'

'

'

'

'

$13,300,000

'

'

$2,100,000

'

'

'

'

'

'

'

'

'

'

Share Based Compensation Nonvested Awards Total Compensation Cost Not Yet Recognized Period For Recognition

'

'

'

'

'

'

'

'

'December 2016

'

'

'August 2016

'

'

'

'

'

'

'

'

'

'

Compensation expense

'

'

'

'

'

'

'

'

16,800,000

15,700,000

13,900,000

3,900,000

7,400,000

7,000,000

'

'

'

'

'

'

'

'

Income tax benefit recognized related to compensation expense

'

'

'

'

'

'

'

'

5,200,000

5,200,000

'

1,300,000

2,400,000

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value

'

'

'

'

'

'

'

'

'

'

'

0

100,000

1,200,000

'

'

'

'

'

'

'

'

Estimated grant date fair value

'

'

'

'

'

'

'

'

22,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of RSUs settled in cash

'

'

'

'

'

'

'

'

4,800,000

1,900,000

'

'

'

'

'

'

'

'

'

'

'

'

Total fair value of shares vested

'

'

'

'

'

'

'

'

7,100,000

16,300,000

13,600,000

'

'

'

'

'

'

'

'

'

'

'

Immaterial Error Correction

'

'5.9

'8.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3.6

'1.2

'2.4

Percentage Of Acquisition By Individual Or Group For Exercisable Of Right To Buy One One Thousandth Of Company Stock By Stockholder

'

'

'

15.00%

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

'

100.00%

'

100.00%

'

'

'

'

'

'

'

'

'

'

30.00%

'

'

'

'

'

'

'

Common Stock Redeemable Rate In Case Of Any Acquisition Proposal

'

'

'

$0.01

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized

'

'

'

'

'

15,000,000

'

14,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized

12,000,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Terms of Award

'

'

'

'10

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant

'

15,400,000

'

15,400,000

9,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Accumulated Other Comprehensive Income (Loss), Net of Tax

'

$109,881,000

'

$109,881,000

$161,493,000

'

'

'

'

'

'

'

'

'

'

$94,500,000

$141,400,000

$15,400,000

$20,100,000

'

'

'

Quicksilver_Stockholders_Equit3

Quicksilver Stockholders' Equity (Common Shares And Treasury Share Activity) (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]	'	'	'	'
Common Stock, Shares, Issued	183,994,879	179,015,118	'	'
Treasury Stock, Shares	6,698,640	5,921,102	'	'
Common Stock [Member]	'	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'	'
Common Stock, Shares, Issued	183,994,879,000	179,015,118,000	176,980,483,000	175,524,816,000
Stock options exercised	0	1,572,000	209,221,000	'
Restricted stock activity	4,979,761,000	2,033,063,000	1,246,446,000	'
Treasury Stock [Member]	'	'	'	'
Schedule of Equity Method Investments [Line Items]	'	'	'	'
Treasury Stock, Shares	6,698,640,000	5,921,102,000	5,379,702,000	5,050,450,000
Stock options exercised	0	0	0	'
Restricted stock activity	777,538,000	541,400,000	329,252,000	'

Quicksilver_Stockholders_Equit4

Quicksilver Stockholders' Equity (Assumptions For The Black-Scholes Option Pricing Model For Stock Options Issued) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]	'	'	'
Weighted avg grant date fair value	$1.05	$4.21	$9.16
Weighted avg risk-free interest rate	1.31%	1.14%	2.38%
Expected life (in years)	'4 years 11 months 9 days	'6 years	'6 years
Wtd avg volatility	68.97%	68.20%	66.77%
Expected dividends	0.00%	0.00%	0.00%

Quicksilver_Stockholders_Equit5

Quicksilver Stockholders' Equity (Stock Option Activity) (Details) (Employee Stock Option [Member], USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2013
Employee Stock Option [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Outstanding at January 1, 2013, Shares	4,979,980
Granted, Shares	2,037,467
Exercised, Shares	0
Forfeited, Shares	-85,004
Expired, Shares	-160,865
Outstanding at December 31, 2013, Shares	6,771,578
Exercisable at December 31, 2013, Shares	4,576,677
Outstanding at January 1, 2013, Wtd Avg Exercise Price	$10.23
Granted, Wtd Avg Exercise Price	$1.95
Exercised, Wtd Avg Exercise Price	$0
Forfeited, Wtd Avg Exercise Price	$6.63
Expired, Wtd Avg Exercise Price	$8.86
Outstanding at December 31, 2013, Wtd Avg Exercise Price	$7.82
Exercisable at December 31, 2013, Wtd Avg Exercise Price	$9.30
Outstanding at December 31, 2013, Wtd Avg Remaining Contractual Life, Years	'6 years 146 days
Exercisable at December 31, 2013, Wtd Avg Remaining Contractual Life, Years	'5 years 98 days
Outstanding at December 31, 2013, Aggregate Intrinsic Value	$0
Exercisable at December 31, 2013, Aggregate Intrinsic Value	$0

Quicksilver_Stockholders_Equit6

Quicksilver Stockholders' Equity (Restricted Stock And Stock Unit Activity) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013
Payable In Shares [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Outstanding at January 1, 2013, Shares	3,099,135
Granted, Shares	6,511,441
Vested, Shares	-2,524,332
Forfeited, Shares	-1,418,154
Outstanding at December 31, 2013, Shares	5,668,090
Outstanding at January 1, 2013, Wtd Avg Grant Date Fair Value	$8.48
Granted, Wtd Avg Grant Date Fair Value	$2.76
Vested, Wtd Avg Grant Date Fair Value	$6.69
Forfeited, Wtd Avg Grant Date Fair Value	$3.68
Outstanding at December 31, 2013, Wtd Avg Grant Date Fair Value	$3.90
Payable In Cash [Member]	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'
Outstanding at January 1, 2013, Shares	678,217
Granted, Shares	1,483,306
Vested, Shares	-284,406
Forfeited, Shares	-304,776
Outstanding at December 31, 2013, Shares	1,572,341
Outstanding at January 1, 2013, Wtd Avg Grant Date Fair Value	$7.71
Granted, Wtd Avg Grant Date Fair Value	$2.81
Vested, Wtd Avg Grant Date Fair Value	$8.51
Forfeited, Wtd Avg Grant Date Fair Value	$3.86
Outstanding at December 31, 2013, Wtd Avg Grant Date Fair Value	$3.69

Earnings_Per_Share_Reconciliat

Earnings Per Share (Reconciliation Of Components Used To Compute Basic And Diluted Net Income Per Common Share) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, except Share data, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Net income (loss) attributable to Quicksilver

($31,775)

$10,577

$242,523

($59,707)

($548,499)

[1]

($790,520)

[2]

($802,022)

($211,565)

$161,618

($2,352,606)

$90,046

Basic income allocable to participating securities

'

'

'

'

'

'

'

'

-4,252

[3]

0

[3]

-1,106

[3]

Net Income (Loss) Available to Common Stockholders, Diluted

'

'

'

'

'

'

'

'

$157,366

($2,352,606)

$88,940

Weighted average common shares - basic

'

'

'

'

'

'

'

'

171,518,000

170,106,000

168,993,000

Share-based compensation awards

'

'

'

'

'

'

'

'

141,000

[4]

0

[4]

742,000

[4]

Weighted average common shares - diluted

'

'

'

'

'

'

'

'

171,659,000

170,106,000

169,735,000

Earnings (loss) per common share - basic

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

($13.83)

$0.53

Earnings (loss) per common share - diluted

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

[4]

($13.83)

[4]

$0.52

[4]

Convertible Debentures [Member]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive shares excluded from the diluted share calculation

'

'

'

'

'

'

'

'

'

'

9,800,000

Employee Stock Option [Member]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive shares excluded from the diluted share calculation

'

'

'

'

'

'

'

'

5,600,000

5,000,000

1,900,000

Restricted Stock Units (RSUs) [Member]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Antidilutive shares excluded from the diluted share calculation

'

'

'

'

'

'

'

'

200,000

300,000

100,000

[1]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[2]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[3]

Restricted share awards that contain nonforfeitable rights to dividends are participating securities and, therefore, should be included in computing earnings using the two-class method. Participating securities, however, do not participate in undistributed net losses because there is no contractual obligation to do so.

[4]

For 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidated Balance Sheets) (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Percentage of ownership interest	100.00%	'
Current assets	$393,960	$207,513
Property, plant and equipment	860,805	1,029,058
Investment in subsidiaries (equity method)	0	0
Other assets	114,961	145,217
Total assets	1,369,726	1,381,788
Current liabilities	134,797	167,791
Long-term liabilities	2,240,899	2,346,794
Stockholders' equity	-1,005,970	-1,132,797
Total liabilities and stockholders' equity	1,369,726	1,381,788
Quicksilver Resources Inc. [Member]	'	'
Current assets	349,586	261,130
Property, plant and equipment	455,822	621,073
Investment in subsidiaries (equity method)	-217,852	-191,725
Other assets	472,792	346,972
Total assets	1,060,348	1,037,450
Current liabilities	124,275	255,678
Long-term liabilities	1,942,043	1,914,568
Stockholders' equity	-1,005,970	-1,132,796
Total liabilities and stockholders' equity	1,060,348	1,037,450
Restricted Guarantor Subsidiaries [Member]	'	'
Current assets	10,735	105,695
Property, plant and equipment	15,486	20,007
Investment in subsidiaries (equity method)	0	0
Other assets	0	0
Total assets	26,221	125,702
Current liabilities	12,210	112,133
Long-term liabilities	19,242	19,242
Stockholders' equity	-5,231	-5,673
Total liabilities and stockholders' equity	26,221	125,702
Restricted Non-Guarantor Subsidiaries [Member]	'	'
Current assets	53,034	76,088
Property, plant and equipment	307,865	296,462
Investment in subsidiaries (equity method)	-33,840	-42,883
Other assets	32,892	41,865
Total assets	359,951	371,532
Current liabilities	17,167	33,475
Long-term liabilities	542,659	524,107
Stockholders' equity	-199,875	-186,050
Total liabilities and stockholders' equity	359,951	371,532
Restricted Subsidiary Eliminations [Member]	'	'
Current assets	-19,642	-222,586
Property, plant and equipment	0	0
Investment in subsidiaries (equity method)	217,852	191,725
Other assets	-390,723	-243,620
Total assets	-192,513	-274,481
Current liabilities	-19,642	-222,586
Long-term liabilities	-390,723	-243,620
Stockholders' equity	217,852	191,725
Total liabilities and stockholders' equity	-192,513	-274,481
Quicksilver And Restricted Subsidiaries [Member]	'	'
Current assets	393,713	220,327
Property, plant and equipment	779,173	937,542
Investment in subsidiaries (equity method)	-33,840	-42,883
Other assets	114,961	145,217
Total assets	1,254,007	1,260,203
Current liabilities	134,010	178,700
Long-term liabilities	2,113,221	2,214,297
Stockholders' equity	-993,224	-1,132,794
Total liabilities and stockholders' equity	1,254,007	1,260,203
Unrestricted Non-Guarantor Subsidiaries [Member]	'	'
Current assets	909	13,250
Property, plant and equipment	0	0
Investment in subsidiaries (equity method)	-33,840	-42,905
Other assets	0	0
Total assets	-32,931	-29,655
Current liabilities	888	13,230
Long-term liabilities	0	0
Stockholders' equity	-33,819	-42,885
Total liabilities and stockholders' equity	-32,931	-29,655
Fortune Creek [Member]	'	'
Current assets	1,110	391
Property, plant and equipment	81,632	91,516
Investment in subsidiaries (equity method)	0	0
Other assets	0	0
Total assets	82,742	91,907
Current liabilities	1,671	2,316
Long-term liabilities	1,546	1,585
Stockholders' equity	79,525	88,006
Total liabilities and stockholders' equity	82,742	91,907
Consolidating Eliminations [Member]	'	'
Current assets	-1,772	-26,455
Property, plant and equipment	0	0
Investment in subsidiaries (equity method)	67,680	85,788
Other assets	0	0
Total assets	65,908	59,333
Current liabilities	-1,772	-26,455
Long-term liabilities	126,132	130,912
Stockholders' equity	-58,452	-45,124
Total liabilities and stockholders' equity	$65,908	$59,333

Condensed_Consolidating_Financ3

Condensed Consolidating Financial Information (Schedule of Condensed Consolidated Statements Of Income (Loss)) (Details) (USD $)

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Revenue

'

'

'

'

'

'

'

'

$561,562

$709,038

$943,623

Operating expenses

'

'

'

'

'

'

'

'

436,246

3,215,896

821,019

Gain on sale of assets

'

'

'

'

'

'

'

'

'

'

0

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Operating income (loss)

13,575

[1]

60,049

[2]

394,894

[3]

-3,874

-468,213

[4]

-576,551

[5]

-1,153,012

[6]

-267,985

[7]

464,644

-2,465,761

122,604

Fortune Creek accretion

'

'

'

'

'

'

'

'

-19,245

-19,472

0

Income (loss) from earnings of BBEP

'

'

'

'

'

'

'

'

0

0

-8,439

Interest expense and other

'

'

'

'

'

'

'

'

-269,231

-162,943

-33,744

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-14,550

295,570

-57,863

Net income (loss)

'

'

'

'

'

'

'

'

161,618

-2,352,606

90,046

Net income (loss) attributable to Quicksilver

-31,775

10,577

242,523

-59,707

-548,499

[4]

-790,520

[5]

-802,022

-211,565

161,618

-2,352,606

90,046

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-51,612

-53,365

67,493

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

17,178

Comprehensive income (loss)

'

'

'

'

'

'

'

'

110,006

-2,405,971

174,717

Quicksilver Resources Inc. [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

416,516

611,477

778,741

Operating expenses

'

'

'

'

'

'

'

'

329,975

2,643,690

603,582

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

-9,896

-437,510

-40,725

Operating income (loss)

'

'

'

'

'

'

'

'

415,973

-2,428,626

134,434

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Income (loss) from earnings of BBEP

'

'

'

'

'

'

'

'

'

'

-8,439

Interest expense and other

'

'

'

'

'

'

'

'

-242,279

-152,077

-39,252

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-12,076

228,097

75,201

Net income (loss)

'

'

'

'

'

'

'

'

161,618

-2,352,606

90,046

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-40,166

-57,273

67,493

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

-11,446

3,908

17,178

Comprehensive income (loss)

'

'

'

'

'

'

'

'

110,006

-2,405,971

174,717

Restricted Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

788

4,574

4,573

Operating expenses

'

'

'

'

'

'

'

'

346

4,109

64,476

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Operating income (loss)

'

'

'

'

'

'

'

'

442

465

-59,903

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Income (loss) from earnings of BBEP

'

'

'

'

'

'

'

'

'

'

0

Interest expense and other

'

'

'

'

'

'

'

'

0

0

-18

Income tax (expense) benefit

'

'

'

'

'

'

'

'

0

-163

-20,960

Net income (loss)

'

'

'

'

'

'

'

'

442

302

-38,925

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

0

0

0

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Comprehensive income (loss)

'

'

'

'

'

'

'

'

442

302

-38,925

Restricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

144,258

95,887

163,864

Operating expenses

'

'

'

'

'

'

'

'

118,481

577,696

156,516

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

-6,682

-12,747

0

Operating income (loss)

'

'

'

'

'

'

'

'

19,095

-494,556

7,348

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Income (loss) from earnings of BBEP

'

'

'

'

'

'

'

'

'

'

0

Interest expense and other

'

'

'

'

'

'

'

'

-26,959

-10,914

5,526

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-2,474

67,658

3,622

Net income (loss)

'

'

'

'

'

'

'

'

-10,338

-437,812

-1,800

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-11,446

3,908

17,178

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Comprehensive income (loss)

'

'

'

'

'

'

'

'

-21,784

-433,904

15,378

Restricted Subsidiary Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

0

-2,900

'

Operating expenses

'

'

'

'

'

'

'

'

0

-2,900

'

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

9,896

437,510

'

Operating income (loss)

'

'

'

'

'

'

'

'

9,896

437,510

'

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Interest expense and other

'

'

'

'

'

'

'

'

0

0

'

Income tax (expense) benefit

'

'

'

'

'

'

'

'

0

0

'

Net income (loss)

'

'

'

'

'

'

'

'

9,896

437,510

'

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

0

0

'

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

11,446

-3,908

'

Comprehensive income (loss)

'

'

'

'

'

'

'

'

21,342

433,602

'

Quicksilver And Restricted Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

561,562

709,038

'

Operating expenses

'

'

'

'

'

'

'

'

448,802

3,222,595

'

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

-6,682

-12,747

'

Operating income (loss)

'

'

'

'

'

'

'

'

445,406

-2,485,207

'

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Interest expense and other

'

'

'

'

'

'

'

'

-269,238

-162,991

'

Income tax (expense) benefit

'

'

'

'

'

'

'

'

-14,550

295,592

'

Net income (loss)

'

'

'

'

'

'

'

'

161,618

-2,352,606

'

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

-51,612

-53,365

'

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

'

Comprehensive income (loss)

'

'

'

'

'

'

'

'

110,006

-2,405,971

'

Unrestricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

0

0

'

Operating expenses

'

'

'

'

'

'

'

'

0

0

'

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

12,563

6,726

'

Operating income (loss)

'

'

'

'

'

'

'

'

12,563

6,726

'

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Interest expense and other

'

'

'

'

'

'

'

'

0

21

'

Income tax (expense) benefit

'

'

'

'

'

'

'

'

0

0

'

Net income (loss)

'

'

'

'

'

'

'

'

12,563

6,747

'

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

0

0

'

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

'

Comprehensive income (loss)

'

'

'

'

'

'

'

'

12,563

6,747

'

Fortune Creek [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

22,364

14,639

'

Operating expenses

'

'

'

'

'

'

'

'

9,808

7,940

'

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

0

0

'

Operating income (loss)

'

'

'

'

'

'

'

'

12,556

6,699

'

Fortune Creek accretion

'

'

'

'

'

'

'

'

0

0

'

Interest expense and other

'

'

'

'

'

'

'

'

7

27

'

Income tax (expense) benefit

'

'

'

'

'

'

'

'

0

0

'

Net income (loss)

'

'

'

'

'

'

'

'

12,563

6,726

'

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

0

0

'

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

'

Comprehensive income (loss)

'

'

'

'

'

'

'

'

12,563

6,726

'

Consolidating Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

-22,364

-14,639

-3,555

Operating expenses

'

'

'

'

'

'

'

'

-22,364

-14,639

-3,555

Equity in net earnings of subsidiaries

'

'

'

'

'

'

'

'

-5,881

6,021

40,725

Operating income (loss)

'

'

'

'

'

'

'

'

-5,881

6,021

40,725

Fortune Creek accretion

'

'

'

'

'

'

'

'

-19,245

-19,472

'

Income (loss) from earnings of BBEP

'

'

'

'

'

'

'

'

'

'

0

Interest expense and other

'

'

'

'

'

'

'

'

0

0

0

Income tax (expense) benefit

'

'

'

'

'

'

'

'

0

-22

0

Net income (loss)

'

'

'

'

'

'

'

'

-25,126

-13,473

40,725

Other comprehensive income (loss)

'

'

'

'

'

'

'

'

0

0

-17,178

Equity in OCI of subsidiaries

'

'

'

'

'

'

'

'

0

0

0

Comprehensive income (loss)

'

'

'

'

'

'

'

'

-25,126

-13,473

23,547

kwk_CrestwoodLP [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

41,097

0

kwk_CrestwoodLP [Member] | Quicksilver Resources Inc. [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

41,097

'

kwk_CrestwoodLP [Member] | Restricted Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

kwk_CrestwoodLP [Member] | Restricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

kwk_CrestwoodLP [Member] | Restricted Subsidiary Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

kwk_CrestwoodLP [Member] | Quicksilver And Restricted Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

41,097

'

kwk_CrestwoodLP [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

kwk_CrestwoodLP [Member] | Fortune Creek [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

kwk_CrestwoodLP [Member] | Consolidating Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

'

0

'

Tokyo Gas [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

339,328

'

'

Tokyo Gas [Member] | Quicksilver Resources Inc. [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

339,328

'

'

Tokyo Gas [Member] | Restricted Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Tokyo Gas [Member] | Restricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Tokyo Gas [Member] | Restricted Subsidiary Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Tokyo Gas [Member] | Quicksilver And Restricted Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

339,328

'

'

Tokyo Gas [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Tokyo Gas [Member] | Fortune Creek [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

0

'

'

Tokyo Gas [Member] | Consolidating Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Gain on sale of assets

'

'

'

'

'

'

'

'

$0

'

'

[1]

Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

[2]

Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR

[3]

Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

[4]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[5]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[6]

Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

[7]

Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information (Schedule of Condensed Consolidated Statements of Cash Flows) (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net cash flow provided (used) by operating activities	($51,700,000)	$227,727,000	$253,053,000
Purchases of property, plant and equipment	-101,288,000	-485,479,000	-690,607,000
Proceeds from Sale and Maturity of Other Investments	0	0	272,965,000
Proceeds from Asset Sales	'	41,097,000	'
Investment in Fortune Creek	'	'	0
Proceeds from sale of properties and equipment	7,171,000	72,725,000	4,163,000
Purchases of marketable securities	-213,738,000	0	0
Proceeds from Sale and Maturity of Marketable Securities	47,603,000	'	'
Net cash used by investing activities	246,044,000	-371,657,000	-413,479,000
Issuance of debt	1,237,352,000	467,959,000	855,822,000
Repayments of debt	-1,308,382,000	-310,430,000	-843,108,000
Debt issuance costs	-26,296,000	-3,022,000	-12,506,000
Distribution of Fortune Creek Partnership funds	-14,965,000	-14,285,000	0
Intercompany Note	0	'	'
Proceeds from exercise of stock options	0	11,000	1,299,000
Purchase of treasury stock	-1,927,000	-3,144,000	-4,864,000
Partnership funds received	0	0	122,913,000
Creation Of Partnership Liability	'	'	0
Net cash flow provided (used) by financing activities	-114,218,000	137,089,000	119,556,000
Effect of exchange rates on cash	4,026,000	-1,354,000	-921,000
Net increase (decrease) in cash and equivalents	84,152,000	-8,195,000	-41,791,000
Cash and cash equivalents at beginning of period	4,951,000	13,146,000	54,937,000
Cash and cash equivalents at end of period	89,103,000	4,951,000	13,146,000
Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	463,999,000	0	0
Synergy [Member]	'	'	'
Proceeds from Asset Sales	42,297,000	0	0
Quicksilver Resources Inc. [Member]	'	'	'
Net cash flow provided (used) by operating activities	-78,565,000	163,353,000	202,043,000
Purchases of property, plant and equipment	-67,263,000	-231,934,000	-518,454,000
Proceeds from Sale and Maturity of Other Investments	'	'	272,965,000
Proceeds from Asset Sales	'	41,097,000	'
Investment in Fortune Creek	'	'	0
Proceeds from sale of properties and equipment	7,128,000	72,362,000	2,959,000
Purchases of marketable securities	-213,738,000	'	'
Proceeds from Sale and Maturity of Marketable Securities	47,603,000	'	'
Net cash used by investing activities	280,026,000	-118,475,000	-242,530,000
Issuance of debt	1,215,266,000	228,500,000	587,500,000
Repayments of debt	-1,157,969,000	-264,018,000	-588,862,000
Debt issuance costs	-26,296,000	-1,972,000	-9,160,000
Distribution of Fortune Creek Partnership funds	0	0	'
Intercompany Note	-147,103,000	'	'
Proceeds from exercise of stock options	'	11,000	1,299,000
Purchase of treasury stock	-1,927,000	-3,144,000	-4,864,000
Partnership funds received	'	'	0
Creation Of Partnership Liability	'	'	0
Net cash flow provided (used) by financing activities	-118,029,000	-40,623,000	-14,087,000
Effect of exchange rates on cash	0	0	0
Net increase (decrease) in cash and equivalents	83,432,000	4,255,000	-54,574,000
Cash and cash equivalents at beginning of period	4,618,000	363,000	54,937,000
Cash and cash equivalents at end of period	88,050,000	4,618,000	363,000
Quicksilver Resources Inc. [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	463,999,000	'	'
Quicksilver Resources Inc. [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	42,297,000	'	'
Restricted Guarantor Subsidiaries [Member]	'	'	'
Net cash flow provided (used) by operating activities	0	656,000	2,225,000
Purchases of property, plant and equipment	0	-656,000	-2,225,000
Proceeds from Sale and Maturity of Other Investments	'	'	0
Proceeds from Asset Sales	'	0	'
Investment in Fortune Creek	'	'	0
Proceeds from sale of properties and equipment	0	0	0
Purchases of marketable securities	0	'	'
Proceeds from Sale and Maturity of Marketable Securities	0	'	'
Net cash used by investing activities	0	-656,000	-2,225,000
Issuance of debt	0	0	0
Repayments of debt	0	0	0
Debt issuance costs	0	0	0
Distribution of Fortune Creek Partnership funds	0	0	'
Intercompany Note	0	'	'
Proceeds from exercise of stock options	'	0	0
Purchase of treasury stock	0	0	0
Partnership funds received	'	'	0
Creation Of Partnership Liability	'	'	0
Net cash flow provided (used) by financing activities	0	0	0
Effect of exchange rates on cash	0	0	0
Net increase (decrease) in cash and equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Restricted Guarantor Subsidiaries [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Restricted Guarantor Subsidiaries [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Restricted Non-Guarantor Subsidiaries [Member]	'	'	'
Net cash flow provided (used) by operating activities	16,456,000	49,271,000	48,785,000
Purchases of property, plant and equipment	-33,520,000	-242,158,000	-169,928,000
Proceeds from Sale and Maturity of Other Investments	'	'	0
Proceeds from Asset Sales	'	0	'
Investment in Fortune Creek	'	'	-12,783,000
Proceeds from sale of properties and equipment	43,000	363,000	1,204,000
Purchases of marketable securities	0	'	'
Proceeds from Sale and Maturity of Marketable Securities	0	'	'
Net cash used by investing activities	-33,477,000	-241,795,000	-181,507,000
Issuance of debt	22,086,000	239,459,000	268,322,000
Repayments of debt	-150,413,000	-46,412,000	-254,246,000
Debt issuance costs	0	-1,050,000	-3,346,000
Distribution of Fortune Creek Partnership funds	0	0	'
Intercompany Note	147,103,000	'	'
Proceeds from exercise of stock options	'	0	0
Purchase of treasury stock	0	0	0
Partnership funds received	'	'	0
Creation Of Partnership Liability	'	'	122,913,000
Net cash flow provided (used) by financing activities	18,776,000	191,997,000	133,643,000
Effect of exchange rates on cash	-1,755,000	527,000	-921,000
Net increase (decrease) in cash and equivalents	0	0	0
Cash and cash equivalents at beginning of period	0	0	0
Cash and cash equivalents at end of period	0	0	0
Restricted Non-Guarantor Subsidiaries [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Restricted Non-Guarantor Subsidiaries [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Quicksilver And Restricted Subsidiaries [Member]	'	'	'
Net cash flow provided (used) by operating activities	-62,109,000	213,280,000	253,053,000
Purchases of property, plant and equipment	-100,783,000	-474,748,000	-690,607,000
Proceeds from Sale and Maturity of Other Investments	'	'	272,965,000
Proceeds from Asset Sales	'	41,097,000	'
Investment in Fortune Creek	'	'	-12,783,000
Proceeds from sale of properties and equipment	7,171,000	72,725,000	4,163,000
Purchases of marketable securities	-213,738,000	'	'
Proceeds from Sale and Maturity of Marketable Securities	47,603,000	'	'
Net cash used by investing activities	246,549,000	-360,926,000	-426,262,000
Issuance of debt	1,237,352,000	467,959,000	855,822,000
Repayments of debt	-1,308,382,000	-310,430,000	-843,108,000
Debt issuance costs	-26,296,000	-3,022,000	-12,506,000
Distribution of Fortune Creek Partnership funds	0	0	'
Intercompany Note	0	'	'
Proceeds from exercise of stock options	'	11,000	1,299,000
Purchase of treasury stock	-1,927,000	-3,144,000	-4,864,000
Partnership funds received	'	'	0
Creation Of Partnership Liability	'	'	122,913,000
Net cash flow provided (used) by financing activities	-99,253,000	151,374,000	119,556,000
Effect of exchange rates on cash	-1,755,000	527,000	-921,000
Net increase (decrease) in cash and equivalents	83,432,000	4,255,000	-54,574,000
Cash and cash equivalents at beginning of period	4,618,000	363,000	54,937,000
Cash and cash equivalents at end of period	88,050,000	4,618,000	363,000
Quicksilver And Restricted Subsidiaries [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	463,999,000	'	'
Quicksilver And Restricted Subsidiaries [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	42,297,000	'	'
Unrestricted Non-Guarantor Subsidiaries [Member]	'	'	'
Net cash flow provided (used) by operating activities	0	0	'
Purchases of property, plant and equipment	0	0	'
Proceeds from Asset Sales	'	0	'
Proceeds from sale of properties and equipment	0	0	'
Purchases of marketable securities	0	'	'
Proceeds from Sale and Maturity of Marketable Securities	0	'	'
Net cash used by investing activities	0	0	'
Issuance of debt	0	0	'
Repayments of debt	0	0	'
Debt issuance costs	0	0	'
Distribution of Fortune Creek Partnership funds	0	0	'
Intercompany Note	0	'	'
Proceeds from exercise of stock options	'	0	'
Purchase of treasury stock	0	0	'
Net cash flow provided (used) by financing activities	0	0	'
Effect of exchange rates on cash	0	0	'
Net increase (decrease) in cash and equivalents	0	0	'
Cash and cash equivalents at beginning of period	0	0	'
Cash and cash equivalents at end of period	0	0	'
Unrestricted Non-Guarantor Subsidiaries [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Unrestricted Non-Guarantor Subsidiaries [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Fortune Creek [Member]	'	'	'
Net cash flow provided (used) by operating activities	10,409,000	14,447,000	0
Purchases of property, plant and equipment	-505,000	-10,731,000	0
Proceeds from Sale and Maturity of Other Investments	'	'	0
Proceeds from Asset Sales	'	0	'
Investment in Fortune Creek	'	'	0
Proceeds from sale of properties and equipment	0	0	0
Purchases of marketable securities	0	'	'
Proceeds from Sale and Maturity of Marketable Securities	0	'	'
Net cash used by investing activities	-505,000	-10,731,000	0
Issuance of debt	0	0	0
Repayments of debt	0	0	0
Debt issuance costs	0	0	0
Distribution of Fortune Creek Partnership funds	-14,965,000	-14,285,000	'
Intercompany Note	0	'	'
Proceeds from exercise of stock options	'	0	0
Purchase of treasury stock	0	0	0
Partnership funds received	'	'	135,696,000
Creation Of Partnership Liability	'	'	-122,913,000
Net cash flow provided (used) by financing activities	-14,965,000	-14,285,000	12,783,000
Effect of exchange rates on cash	5,781,000	-1,881,000	0
Net increase (decrease) in cash and equivalents	720,000	-12,450,000	12,783,000
Cash and cash equivalents at beginning of period	333,000	12,783,000	0
Cash and cash equivalents at end of period	1,053,000	333,000	12,783,000
Fortune Creek [Member] | Tokyo Gas [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Fortune Creek [Member] | Synergy [Member]	'	'	'
Proceeds from Asset Sales	0	'	'
Consolidation, Eliminations [Member]	'	'	'
Net cash flow provided (used) by operating activities	'	'	0
Purchases of property, plant and equipment	'	'	0
Proceeds from Sale and Maturity of Other Investments	'	'	0
Investment in Fortune Creek	'	'	12,783,000
Proceeds from sale of properties and equipment	'	'	0
Net cash used by investing activities	'	'	12,783,000
Issuance of debt	'	'	0
Repayments of debt	'	'	0
Debt issuance costs	'	'	0
Proceeds from exercise of stock options	'	'	0
Purchase of treasury stock	'	'	0
Partnership funds received	'	'	-12,783,000
Creation Of Partnership Liability	'	'	0
Net cash flow provided (used) by financing activities	'	'	-12,783,000
Effect of exchange rates on cash	'	'	0
Net increase (decrease) in cash and equivalents	'	'	0
Cash and cash equivalents at beginning of period	'	'	0
Cash and cash equivalents at end of period	'	'	$0

Segment_Information_Operating_

Segment Information (Operating Income And Property And Equipment Costs Incurred) (Details) (USD $)

3 Months Ended

12 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Number of geographical segments

2

'

'

'

'

'

'

'

2

'

'

Revenue

$114,246,000

$153,116,000

$175,497,000

$118,703,000

$223,966,000

$118,188,000

$194,018,000

$172,866,000

$561,562,000

$709,038,000

$943,623,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

62,612,000

163,624,000

225,763,000

DD&A

'

'

'

'

'

'

'

'

62,612,000

163,624,000

225,763,000

Impairment expense

'

'

'

'

'

'

'

'

1,863,000

2,625,928,000

107,059,000

Operating income (loss)

13,575,000

[1]

60,049,000

[2]

394,894,000

[3]

-3,874,000

-468,213,000

[4]

-576,551,000

[5]

-1,153,012,000

[6]

-267,985,000

[7]

464,644,000

-2,465,761,000

122,604,000

Property and equipment costs incurred

'

'

'

'

'

'

'

'

98,661,000

390,456,000

694,479,000

Property, plant and equipment, net

860,805,000

'

'

'

1,029,058,000

'

'

'

860,805,000

1,029,058,000

'

Assets

1,369,726,000

'

'

'

1,381,788,000

'

'

'

1,369,726,000

1,381,788,000

'

UNITED STATES

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

416,462,000

598,892,000

806,657,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

37,540,000

123,370,000

'

DD&A

'

'

'

'

'

'

'

'

'

'

171,438,000

Impairment expense

'

'

'

'

451,500,000

479,900,000

1,042,700,000

178,000,000

1,809,000

2,152,665,000

0

Operating income (loss)

'

'

'

'

'

'

'

'

476,610,000

-1,921,073,000

251,495,000

Property and equipment costs incurred

'

'

'

'

'

'

'

'

64,976,000

189,997,000

487,145,000

Property, plant and equipment, net

451,840,000

'

'

'

614,071,000

'

'

'

451,840,000

614,071,000

'

Assets

895,388,000

'

'

'

784,104,000

'

'

'

895,388,000

784,104,000

'

Canada [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

141,870,000

105,949,000

135,948,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

17,508,000

32,686,000

'

DD&A

'

'

'

'

'

'

'

'

'

'

47,116,000

Impairment expense

'

'

'

'

102,800,000

66,300,000

157,000,000

139,900,000

0

465,935,000

49,063,000

Operating income (loss)

'

'

'

'

'

'

'

'

32,648,000

-474,768,000

12,914,000

Property and equipment costs incurred

'

'

'

'

'

'

'

'

16,838,000

174,867,000

131,699,000

Property, plant and equipment, net

306,423,000

'

'

'

294,921,000

'

'

'

306,423,000

294,921,000

'

Assets

359,951,000

'

'

'

371,532,000

'

'

'

359,951,000

371,532,000

'

Midstream [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

25,594,000

21,735,000

4,573,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

5,249,000

5,182,000

'

DD&A

'

'

'

'

'

'

'

'

'

'

4,889,000

Impairment expense

'

'

'

'

'

'

'

'

54,000

7,328,000

57,996,000

Operating income (loss)

'

'

'

'

'

'

'

'

13,008,000

8,163,000

-59,903,000

Property and equipment costs incurred

'

'

'

'

'

'

'

'

7,055,000

18,742,000

64,119,000

Property, plant and equipment, net

97,118,000

'

'

'

111,523,000

'

'

'

97,118,000

111,523,000

'

Assets

108,963,000

'

'

'

217,609,000

'

'

'

108,963,000

217,609,000

'

Corporate [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

0

0

0

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

2,315,000

2,386,000

'

DD&A

'

'

'

'

'

'

'

'

'

'

2,320,000

Impairment expense

'

'

'

'

'

'

'

'

0

0

0

Operating income (loss)

'

'

'

'

'

'

'

'

-57,622,000

-78,083,000

-81,902,000

Property and equipment costs incurred

'

'

'

'

'

'

'

'

9,792,000

6,850,000

11,516,000

Property, plant and equipment, net

5,424,000

'

'

'

8,543,000

'

'

'

5,424,000

8,543,000

'

Assets

5,424,000

'

'

'

8,543,000

'

'

'

5,424,000

8,543,000

'

Intersegment Eliminations [Member]

'

'

'

'

'

'

'

'

'

'

'

Segment Reporting Information [Line Items]

'

'

'

'

'

'

'

'

'

'

'

Revenue

'

'

'

'

'

'

'

'

-22,364,000

-17,538,000

-3,555,000

Depletion, depreciation and accretion

'

'

'

'

'

'

'

'

0

0

'

DD&A

'

'

'

'

'

'

'

'

'

'

0

Impairment expense

'

'

'

'

'

'

'

'

0

0

0

Operating income (loss)

'

'

'

'

'

'

'

'

0

0

0

Property and equipment costs incurred

'

'

'

'

'

'

'

'

0

0

0

Property, plant and equipment, net

0

'

'

'

0

'

'

'

0

0

'

Assets

$0

'

'

'

$0

'

'

'

$0

$0

'

[1]

Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

[2]

Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR

[3]

Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

[4]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[5]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[6]

Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

[7]

Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information (Cash Paid Or Received For Interest And Income Taxes) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Abstract]	'	'	'
Interest, net of capitalized interest	$254,901	$154,663	$170,814
Income taxes	($833)	$20,682	$4,249

Supplemental_Cash_Flow_Informa3

Supplemental Cash Flow Information (Other Significant Noncash Transactions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Dividends Payable [Line Items]	'	'	'
Working Capital Related To Capital Expenditures	$10,324	$10,939	$107,586
Note Receivable Received For Sale Of Land And Building	$0	$0	$5,300

Employee_Benefits_Details

Employee Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Employee Benefits [Line Items]	'	'	'
Age limit for retirement plan	21	'	'
Health Care Organization Individual Stop Loss On Health Benefit Plan	$125,000	'	'
Expenses associated with health benefit plan	4,000,000	5,000,000	4,800,000
United States Of America [Member]	'	'	'
Employee Benefits [Line Items]	'	'	'
Expenses associated with company contributions	1,800,000	2,300,000	2,300,000
Canada [Member]	'	'	'
Employee Benefits [Line Items]	'	'	'
Expenses associated with company contributions	$700,000	$700,000	$800,000

Transactions_With_Related_Part1

Transactions With Related Parties (Details) (USD $)

Dec. 31, 2013

Oct. 31, 2011

Feb. 15, 2014

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

31-May-13

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

31-May-13

31-May-13

Darden Family [Member]

Darden Family [Member]

Mercury Exploration Company [Member]

Mercury Exploration Company [Member]

Mercury Exploration Company [Member]

Thomas F. Darden [Member]

Rent On Buildings [Member]

Rent On Buildings [Member]

Commissions Paid [Member]

Use Of Airplane [Member]

Use Of Airplane [Member]

Use Of Airplane [Member]

Restricted Stock [Member]

Employee Stock Option [Member]

Darden Family [Member]

Darden Family [Member]

Darden Family [Member]

Darden Family [Member]

Darden Family [Member]

Darden Family [Member]

Thomas F. Darden [Member]

Thomas F. Darden [Member]

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Percentage of ownership interest

100.00%

'

30.00%

'

'

'

'

'

'

'

'

'

'

'

'

Payments to related parties

'

'

'

'

'

'

'

$100,000

$200,000

$200,000

$300,000

$500,000

$900,000

'

'

Purchase Price Of The Manufacturing Facility Of An Entity

'

1,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Related Party Transaction, Revenues from Transactions with Related Party

'

'

'

100,000

100,000

100,000

'

'

'

'

'

'

'

'

'

Monthly Business Expense Allowance

'

'

'

'

'

'

12,500

'

'

'

'

'

'

'

'

Cash Bonus Related to Tokyo Gas Transaction

'

'

'

'

'

'

1,100,000

'

'

'

'

'

'

'

'

Stock Granted, Value, Share-based Compensation, Gross

'

'

'

'

'

'

1,100,000

'

'

'

'

'

'

'

'

Unvested Equity Awards

'

'

'

'

'

'

'

'

'

'

'

'

'

242,724

304,407

Legal Fee Reimbursement Allowance

'

'

'

'

'

'

40,000

'

'

'

'

'

'

'

'

Monthly Consulting Fee

'

'

'

'

'

'

45,000

'

'

'

'

'

'

'

'

Maximum Bonus Eligibility

'

'

'

'

'

'

$2,500,000

'

'

'

'

'

'

'

'

Supplemental_Selected_Quarterl2

Supplemental Selected Quarterly Financial Data (Unaudited) Supplemental Selected Quarterly Financial Data (Schedule Of Quarterly Financial Data - Unaudited) (Details) (USD $)

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

12 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2013

U.S. [Member]

U.S. [Member]

U.S. [Member]

U.S. [Member]

U.S. [Member]

U.S. [Member]

U.S. [Member]

Canada [Member]

Canada [Member]

Canada [Member]

Canada [Member]

Canada [Member]

Canada [Member]

Canada [Member]

Tokyo Gas [Member]

Tokyo Gas [Member]

Tokyo Gas [Member]

Tokyo Gas [Member]

compensation expense correction [Domain]

compensation expense correction [Domain]

compensation expense correction [Domain]

adjustment to Tokyo Gas Transaction [Member]

adjustment to Tokyo Gas Transaction [Member]

expense to settle litigation correction [Member]

amortization of deferred financing costs correction [Member]

strategic transaction fees correction [Member]

Schedule Of Quarterly Financial Data [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain on Tokyo Gas Transaction

'

'

'

'

'

'

'

'

'

'

$0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

$333,200,000

$339,328,000

$0

$0

'

'

'

'

'

'

'

'

Immaterial Error Correction

'5.9

'8.2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'3.6

'1.2

'2.4

'1.7

'7.8

'3.0

'.8

'.5

Operating revenue

114,246,000

153,116,000

175,497,000

118,703,000

223,966,000

118,188,000

194,018,000

172,866,000

561,562,000

709,038,000

943,623,000

'

'

'

'

416,462,000

598,892,000

806,657,000

'

'

'

'

141,870,000

105,949,000

135,948,000

'

'

'

'

'

'

'

'

'

'

'

'

Operating income

13,575,000

[1]

60,049,000

[2]

394,894,000

[3]

-3,874,000

-468,213,000

[4]

-576,551,000

[5]

-1,153,012,000

[6]

-267,985,000

[7]

464,644,000

-2,465,761,000

122,604,000

'

'

'

'

476,610,000

-1,921,073,000

251,495,000

'

'

'

'

32,648,000

-474,768,000

12,914,000

'

'

'

'

'

'

'

'

'

'

'

'

Net income

-31,775,000

10,577,000

242,523,000

-59,707,000

-548,499,000

[4]

-790,520,000

[5]

-802,022,000

-211,565,000

161,618,000

-2,352,606,000

90,046,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Basic net earnings per share

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

($13.83)

$0.53

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Diluted net earnings per share

($0.18)

$0.06

$1.37

($0.35)

($3.22)

($4.65)

($4.72)

($1.24)

$0.92

[8]

($13.83)

[8]

$0.52

[8]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Impairment expense

'

'

'

'

'

'

'

'

1,863,000

2,625,928,000

107,059,000

451,500,000

479,900,000

1,042,700,000

178,000,000

1,809,000

2,152,665,000

0

102,800,000

66,300,000

157,000,000

139,900,000

0

465,935,000

49,063,000

'

'

'

'

'

'

'

'

'

'

'

'

Other asset impairment charges

'

'

'

'

2,900,000

4,900,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Tax Valuation Allowance Expense, Federal

'

'

'

'

'

'

'

'

($186,713,000)

$533,974,000

$0

'

$359,900,000

'

'

'

'

'

$61,300,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

Operating income for the fourth quarter of 2013 includes a decrease of $5.9 million to correct for immaterial items which pertain to prior 2013 quarters. These items include an adjustment to non-cash expense to settle litigation recognized in the first quarter of 2013 of $3.0 million, non-cash decrease in the gain related to the Tokyo Gas Transaction of $1.7 million arising from a change in the amount of surface real estate conveyed to TGBR, increase in the amortization of deferred financing costs and original issue discount of $0.8 million and strategic transaction fees of $0.5 million arising in the second quarter of 2013.

[2]

Operating income for the third quarter of 2013 includes an increase of $8.2 million to correct for immaterial items which pertain to earlier quarters in 2013, comprised of an increase to the gain related to the Tokyo Gas Transaction of $7.8 million arising from a change to the amount of unevaluated properties allocated to TGBR

[3]

Operating income for the second quarter of 2013 includes gains of $333.2 million related to the Tokyo Gas Transaction which was subsequently adjusted in later quarters to be a gain of $339.3 million. The period also includes an immaterial correction of $3.6 million for equity-based compensation granted to retirement-eligible employees whose awards required no future service at the time of grant but which expense was being recognized over multiple periods. The impact to the first quarter of 2013 expense was $1.2 million and the impact to 2012 and prior years was $2.4 million.

[4]

Operating loss for the fourth quarter of 2012 includes charges for impairment of $451.5 million and $102.8 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $2.9 million impairment charge related to non-oil and gas properties. Net loss includes a valuation allowance for Canada of $61.3 million.

[5]

Operating loss for the third quarter of 2012 includes charges for impairment of $479.9 million and $66.3 million for our U.S. and Canadian oil and gas properties, respectively. Operating loss also includes a $4.9 million impairment charge for other property and equipment in Colorado. Net loss includes a valuation allowance for the U.S. of

[6]

Operating loss for the second quarter of 2012 includes charges for impairment of $1,042.7 million and $157.0 million for our U.S. and Canadian oil and gas properties, respectively.

[7]

Operating loss for the first quarter of 2012 includes charges for impairment of $178.0 million and $139.9 million for our U.S. and Canadian oil and gas properties, respectively.

[8]

For 2013, 5.6 million shares associated with our stock options and 0.2 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2012, 5.0 million shares associated with our stock options and 0.3 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. For 2011, the effects of 9.8 million shares associated with our convertible debentures for the period outstanding were antidilutive, and 1.9 million shares associated with our stock options and 0.1 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations.

Supplemental_Oil_and_Gas_Infor2

Supplemental Oil and Gas Information (Unaudited) Reserve Rollforward (Details)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	Mcf		Mcf		Mcf
Reserve Quantities [Line Items]	'		'		'
Revisions, Removal of Proved Undeveloped Reserves not Developed	76		250		'
Percentage of ownership interest	100.00%		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Revisions, Changes in Performance	74		291		'
U.S. [Member] | Proved Developed [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions, Percent	'		13.00%		'
U.S. [Member] | Natural Gas [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	848,048		1,828,904		1,941,723
Revisions	234,835	[1]	-910,386	[1]	-172,643	[1]
Extensions and discoveries	50,992	[2]	25,858	[2]	155,662	[2]
Sales in place	-257,741	[3]	-20,616	[4]	'
Production	-51,684		-75,712		-95,838
Proved Reserves, End of Period	824,450		848,048		1,828,904
Proved Developed Reserves (Volume)	702,147		725,361		1,244,187
Proved Undeveloped Reserve (Volume)	122,303		122,687		584,717
U.S. [Member] | NGL [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	56,173		102,145		112,444
Revisions	750	[1]	-45,379	[1]	-8,519	[1]
Extensions and discoveries	0	[2]	3,518	[2]	2,652	[2]
Sales in place	-14,333	[3]	-42	[4]	'
Production	-2,856		-4,069		-4,432
Proved Reserves, End of Period	39,734		56,173		102,145
Proved Developed Reserves (Volume)	34,603		47,284		60,902
Proved Undeveloped Reserve (Volume)	5,131		8,890		41,243
U.S. [Member] | Oil [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	2,529		3,035		3,308
Revisions	62	[1]	-479	[1]	-43	[1]
Extensions and discoveries	0	[2]	345	[2]	43	[2]
Sales in place	-2,207	[3]	-85	[4]	'
Production	-185		-287		-273
Proved Reserves, End of Period	199		2,529		3,035
Proved Developed Reserves (Volume)	139		2,416		2,545
Proved Undeveloped Reserve (Volume)	60		113		490
Canada [Member] | Natural Gas [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	266,783		330,631		265,888
Revisions	28,648	[1]	-33,945	[1]	15,066	[1]
Extensions and discoveries	9,697	[2]	9	[2]	76,067	[2]
Sales in place	0	[3]	0	[4]	'
Production	-39,372		-29,912		-26,390
Proved Reserves, End of Period	265,756		266,783		330,631
Proved Developed Reserves (Volume)	260,159		266,783		299,371
Proved Undeveloped Reserve (Volume)	5,896		0		31,260
Canada [Member] | NGL [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	10		11		12
Revisions	0	[1]	1	[1]	1	[1]
Extensions and discoveries	0	[2]	0	[2]	0	[2]
Sales in place	0	[3]	0	[4]	'
Production	-1		-2		-2
Proved Reserves, End of Period	9		10		11
Proved Developed Reserves (Volume)	9		10		11
Proved Undeveloped Reserve (Volume)	0		0		0
Canada [Member] | Oil [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	0		0		0
Revisions	0	[1]	0	[1]	0	[1]
Extensions and discoveries	0	[2]	0	[2]	0	[2]
Sales in place	0	[3]	0	[4]	'
Production	0		0		0
Proved Reserves, End of Period	0		0		0
Proved Developed Reserves (Volume)	0		0		0
Proved Undeveloped Reserve (Volume)	0		0		0
Consolidated [Member] | Natural Gas [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	1,114,831		2,159,535		2,207,611
Revisions	263,483	[1]	-944,331	[1]	-157,577	[1]
Extensions and discoveries	60,689	[2]	25,867	[2]	231,729	[2]
Sales in place	-257,741	[3]	-20,616	[4]	'
Production	-91,056		-105,624		-122,228
Proved Reserves, End of Period	1,090,206		1,114,831		2,159,535
Proved Developed Reserves (Volume)	962,306		992,144		1,543,558
Proved Undeveloped Reserve (Volume)	128,199		122,687		615,977
Consolidated [Member] | NGL [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	56,183		102,156		112,456
Revisions	750	[1]	-45,378	[1]	-8,518	[1]
Extensions and discoveries	0	[2]	3,518	[2]	2,652	[2]
Sales in place	-14,333	[3]	-42	[4]	'
Production	-2,857		-4,071		-4,434
Proved Reserves, End of Period	39,743		56,183		102,156
Proved Developed Reserves (Volume)	34,612		47,294		60,913
Proved Undeveloped Reserve (Volume)	5,131		8,890		41,243
Consolidated [Member] | Oil [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Proved Reserves, Beginning of Period	2,529		3,035		3,308
Revisions	62	[1]	-479	[1]	-43	[1]
Extensions and discoveries	0	[2]	345	[2]	43	[2]
Sales in place	-2,207	[3]	-85	[4]	'
Production	-185		-287		-273
Proved Reserves, End of Period	199		2,529		3,035
Proved Developed Reserves (Volume)	139		2,416		2,545
Proved Undeveloped Reserve (Volume)	60		113		490
Changes in Non-Economic Factors [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Revisions	-151,615		-629,407		-154,405
Changes in Economic Factors [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Revisions	419,972		-590,064		-54,539
Barnett Shale [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions, Percent	'		96.00%		100.00%
Barnett Shale [Member] | U.S. [Member] | Proved Developed [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions, Percent	'		'		11.00%
Niobrara and West Texas Assets [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions, Percent	'		4.00%		'
Tokyo Gas [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Sales in place	337		'		'
Synergy [Member]	'		'		'
Change in Proved Developed and Undeveloped Reserves [Roll Forward]	'		'		'
Sales in place	15		'		'
[1]	Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in economic factors of 419,972B MMcfe, (590,064) MMcfe and (54,539) MMcfe in 2013, 2012 and 2011, respectively, and changes in non-economic factors of (151,615)B MMcfe, (629,407)B MMcfe and (154,405) MMcfe in 2013, 2012 and 2011, respectively, including:b"Removal of proved undeveloped reserves that had not been developed within five years: (76) Bcfe and (250) Bcfe in 2013 and 2012, respectively;b"changes in performance related to offsetting activities, higher pipeline pressures and other factors: (74) Bcfe and (291) Bcfe in 2013 and 2012, respectively andb"revision of type curve of non producing wells based on comparison to producing analogs: (88) Bcfe in 2012.
[2]	Extensions and discoveries for each period presented represent extensions to reserves attributable to additional drilling activity subsequent to discovery. U.S. extensions and discoveries for:b"2013 are attributable to our Barnett Shale Asset;b"2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed); andb"2011 are 100% attributable to our Barnett Shale Asset (of which 11% were proved developed).Canadian extensions and discoveries for:b"2013 and 2012 are attributable to our Horseshoe Canyon Asset; andb"2011 are 97% attributable to our Horn River Asset and 3% are attributable to our Horseshoe Canyon Asset
[3]	Sales of reserves in place during 2013 relate to the Tokyo Gas Transaction (337 Bcfe) and the Synergy Transaction (15 Bcfe).
[4]	Sales of reserves in place during 2012 relate to our agreement to allow an outside working interest owner to fund the completion costs for twelve wells in our Barnett Shale Asset for which they received a preferential right to reserves. It also includes a minimal sale of reserves in our Niobrara Asset to SWEPI.

Supplemental_Oil_and_Gas_Infor3

Supplemental Oil and Gas Information (Unaudited) Net Carrying Value of Assets (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Accumulated DD&A	($5,268,719)	($5,297,220)	'
Net oil and gas properties	640,443	780,960	'
U.S. [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Proved properties	4,645,777	4,681,860	4,380,745
Unevaluated properties	19,343	90,035	252,737
Accumulated DD&A	-4,268,387	-4,233,391	-1,965,258
Net oil and gas properties	396,733	538,504	2,668,224
Canada [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Proved properties	1,041,780	1,089,053	928,585
Unevaluated properties	202,262	217,232	180,604
Accumulated DD&A	-1,000,332	-1,063,829	-550,937
Net oil and gas properties	243,710	242,456	558,252
Consolidated [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Proved properties	5,687,557	5,770,913	5,309,330
Unevaluated properties	221,605	307,267	433,341
Accumulated DD&A	-5,268,719	-5,297,220	-2,516,195
Net oil and gas properties	$640,443	$780,960	$3,226,476

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) Captial Costs Incurred For Acquisition, Exploration and Development Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Asset retirement costs	$1,560	$1,846	'
U.S. [Member]	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Proved acreage	0	0	0
Unproved acreage	15,843	23,711	145,099
Development costs	49,299	131,926	304,373
Exploration costs	0	35,244	37,673
Total	65,142	190,881	487,145
Canada [Member]	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Proved acreage	0	0	0
Unproved acreage	6,305	5,612	0
Development costs	17,422	178,808	90,361
Exploration costs	0	8,304	41,338
Total	23,727	192,724	131,699
Consolidated [Member]	'	'	'
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]	'	'	'
Proved acreage	0	0	0
Unproved acreage	22,148	29,323	145,099
Development costs	66,721	310,734	394,734
Exploration costs	0	43,548	79,011
Total	$88,869	$383,605	$618,844

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) Results from Producing Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Income (loss) before income taxes	$176,168	($2,648,176)	$147,909
U.S. [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Natural gas, NGL and oil revenue	331,964	538,902	673,041
Operating expense	167,425	226,542	267,890
Depletion expense	34,995	116,005	164,493
Impairment expense	'	2,152,128	0
Income (loss) before income taxes	129,544	-1,955,773	240,658
Income tax expense (benefit)	45,340	-684,521	84,230
Results of midstream operations, net of income tax	84,204	-1,271,252	156,428
Canada [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Natural gas, NGL and oil revenue	131,527	92,045	127,502
Operating expense	80,475	60,501	54,770
Depletion expense	5,362	24,897	38,228
Impairment expense	'	465,935	49,063
Income (loss) before income taxes	45,690	-459,288	-14,559
Income tax expense (benefit)	11,514	-114,822	-4,222
Results of midstream operations, net of income tax	34,176	-344,466	-10,337
Consolidated [Member]	'	'	'
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]	'	'	'
Natural gas, NGL and oil revenue	463,491	630,947	800,543
Operating expense	247,900	287,043	322,660
Depletion expense	40,357	140,902	202,721
Impairment expense	'	2,618,063	49,063
Income (loss) before income taxes	175,234	-2,415,061	226,099
Income tax expense (benefit)	56,854	-799,343	80,008
Results of midstream operations, net of income tax	$118,380	($1,615,718)	$146,091

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) Prices used for Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Natural Gas [Member] | Henry Hub [Member]	'	'	'
Supplemental Oil and Gas Information [Line Items]	'	'	'
Representative prices	3.67	2.76	4.12
Natural Gas [Member] | AECO [Member]	'	'	'
Supplemental Oil and Gas Information [Line Items]	'	'	'
Representative prices	2.9	2.35	3.65
Oil [Member] | WTI Cushing [Member]	'	'	'
Supplemental Oil and Gas Information [Line Items]	'	'	'
Representative prices	97.18	94.71	95.71

Supplemental_Oil_and_Gas_Infor7

Supplemental Oil and Gas Information (Unaudited) Discounted Future Cash Flows of Proved Reserves (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
U.S. [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future revenue	$3,825,944	$3,980,643	$11,647,002
Future production costs	-2,022,977	-2,552,863	-5,496,246
Future development costs	-212,280	-239,532	-1,125,641
Future income taxes	-134,418	81,847	-1,229,968
Future net cash flows	1,456,269	1,270,095	3,795,147
10% discount	-801,116	-667,738	-2,286,449
Standardized measure of discounted future cash flows relating to proved reserves	655,153	602,357	1,508,698
Canada [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future revenue	656,984	472,539	1,055,711
Future production costs	-385,776	-324,424	-463,852
Future development costs	-79,525	-56,354	-146,658
Future income taxes	59,294	80,206	-44,183
Future net cash flows	250,977	171,967	401,018
10% discount	-83,082	-59,204	-174,863
Standardized measure of discounted future cash flows relating to proved reserves	167,895	112,763	226,155
Consolidated [Member]	'	'	'
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]	'	'	'
Future revenue	4,482,928	4,453,182	12,702,713
Future production costs	-2,408,753	-2,877,287	-5,960,098
Future development costs	-291,805	-295,886	-1,272,299
Future income taxes	-75,124	162,053	-1,274,151
Future net cash flows	1,707,246	1,442,062	4,196,165
10% discount	-884,198	-726,942	-2,461,312
Standardized measure of discounted future cash flows relating to proved reserves	$823,048	$715,120	$1,734,853

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) Changes in Standardized Measure of Discounted Future Net Cash Flows (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Sales of oil and gas net of production costs	($147,402)	($149,326)	($477,883)
Net changes in economic factors	326,698	-1,362,793	32,175
Extensions and discoveries	43,328	27,003	251,635
Development costs incurred	2,302	172,563	233,294
Changes in estimated future development costs	20,766	620,127	-60,642
Purchase and sale of reserves, net	-237,409	-20,529	0
Revision of estimates	121,916	-1,219,609	-224,784
Accretion of discount	50,821	196,315	197,902
Net change in income taxes	-86,667	560,485	1,404
Change in timing and other differences	13,575	156,031	-4,626
Net increase (decrease)	$107,928	($1,019,733)	($51,525)

Supplemental_Oil_and_Gas_Infor9

Supplemental Oil and Gas Information (Unaudited) Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
	MMcf		MMcf
Reserve Quantities [Line Items]	'		'		'
Future net cash inflows after income taxes, annual discount rate	10.00%		'		'
Proved undeveloped reserves that had not been developed, Period	'5 years		'		'
Removal of proved undeveloped reserves not developed	76		250		'
Changes in performance	74		291		'
Revision of type curve of non producing wells	'		88		'
Capital expenditures	$101,288		$485,479		$690,607
Barnett Shale Asset [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		96.00%		100.00%
Niobrara and West Texas Assets [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		4.00%		'
Horn River Asset [Member] | Canada [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		'		97.00%
Horseshoe Canyon Asset [Member] | Canada [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		'		3.00%
Proved Developed [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		13.00%		'
Proved Developed [Member] | Barnett Shale Asset [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Extensions and discoveries, Percent	'		'		11.00%
Natural Gas [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	234,835	[1]	-910,386	[1]	-172,643	[1]
Proved developed	702,147		725,361		1,244,187
Natural Gas [Member] | Canada [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	28,648	[1]	-33,945	[1]	15,066	[1]
Proved developed	260,159		266,783		299,371
Oil [Member] | U.S. [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	62	[1]	-479	[1]	-43	[1]
Proved developed	139		2,416		2,545
Oil [Member] | Canada [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	0	[1]	0	[1]	0	[1]
Proved developed	0		0		0
Changes in Economic Factors [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	419,972		-590,064		-54,539
Changes in Non-Economic Factors [Member]	'		'		'
Reserve Quantities [Line Items]	'		'		'
Revisions	-151,615		-629,407		-154,405
[1]	Revisions for each period presented reflect upward (downward) changes in previous estimates attributable to changes in economic factors of 419,972B MMcfe, (590,064) MMcfe and (54,539) MMcfe in 2013, 2012 and 2011, respectively, and changes in non-economic factors of (151,615)B MMcfe, (629,407)B MMcfe and (154,405) MMcfe in 2013, 2012 and 2011, respectively, including:b"Removal of proved undeveloped reserves that had not been developed within five years: (76) Bcfe and (250) Bcfe in 2013 and 2012, respectively;b"changes in performance related to offsetting activities, higher pipeline pressures and other factors: (74) Bcfe and (291) Bcfe in 2013 and 2012, respectively andb"revision of type curve of non producing wells based on comparison to producing analogs: (88) Bcfe in 2012.