Quicksilver Resources (KWK) 10-K 31 Mar 15 2014 FY Annual report Financial data

Document_And_Entity_Informatio

Document And Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Mar. 17, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Entity Registrant Name	QUICKSILVER RESOURCES INC
Entity Central Index Key	1060990
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		183,213,235
Entity Well-known Seasoned Issuer	No
Entity Public Float			$335,217,945
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
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue
Production													$425,154	$463,491	$630,947
Sales of purchased natural gas													70,468	64,913	62,405
Net derivative gains													65,698	29,928	11,444
Other													8,108	3,230	4,242
Total revenue													569,428	561,562	709,038
Operating expense
Lease operating													76,975	82,265	95,333
Gathering, processing and transportation													136,283	148,569	166,316
Production and ad valorem taxes													17,344	17,066	25,395
Cost of purchased natural gas													70,376	64,840	62,041
Depletion, depreciation and accretion													61,126	62,612	163,624
Impairment	71,900												71,988	1,863	2,625,928
General and administrative													47,294	55,306	75,697
Other operating													2,608	3,725	1,562
Total expense													483,994	436,246	3,215,896
Operating income (loss)	18,168	[1]	64,784	13,536	-11,054	13,575	[2]	60,049	[3]	394,894	[4]	-3,874	85,434	464,644	-2,465,761
Other income (expense) - net													-6,581	-17,384	1,108
Fortune Creek accretion													-15,067	-19,245	-19,472
Interest expense													-163,286	-251,847	-164,051
Income (loss) before income taxes													-99,500	176,168	-2,648,176
Income tax (expense) benefit													-3,600	-14,550	295,570
Net income (loss)													-103,100	161,618	-2,352,606
Other comprehensive income (loss)
Reclassification adjustments related to settlements of derivative contracts into production revenue- net of income tax													-24,702	-46,931	-128,161
Net change in derivative fair value - net of income tax													0	0	74,384
Foreign currency translation adjustment													-13,326	-4,681	412
Other comprehensive income (loss)													-38,028	-51,612	-53,365
Comprehensive income (loss)													-141,128	110,006	-2,405,971
Earnings (loss) per common share - basic	($0.18)		$0.13	($0.21)	($0.34)	($0.18)		$0.06		$1.37		($0.35)	($0.59)	$0.92	($13.83)
Earnings (loss) per common share - diluted	($0.18)		$0.13	($0.21)	($0.34)	($0.18)		$0.06		$1.37		($0.35)	($0.59)	$0.92	($13.83)
Tokyo Gas [Member]
Operating expense
Gain on Tokyo Gas Transaction										333,200			0	339,328	0
kwk_CrestwoodLP [Member]
Operating expense
Crestwood earn-out													$0	$0	$41,097
[1]	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
[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 $8.0 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.

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Current assets
Cash and cash equivalents	$223,529	$89,103	$4,951	$13,146
Marketable securities	0	166,343
Cash, Cash Equivalents, and Short-term Investments	223,529	255,446
Accounts receivable - net of allowance for doubtful accounts	65,158	58,645
Derivative assets at fair value	120,176	57,523
Other current assets	14,414	22,346
Total current assets	423,277	393,960
Property, plant and equipment - net
Oil and natural gas properties, full cost method (including unevaluated costs of $18,803 and $221,605, respectively)	614,668	640,443
Other property and equipment	114,112	220,362
Property, plant and equipment - net	728,780	860,805
Derivative assets at fair value	29,391	73,357
Other assets	32,854	41,604
Total assets	1,214,302	1,369,726
Current liabilities
Long-term Debt, Current Maturities	2,037,305	0
Accounts payable	22,586	28,822
Accrued liabilities	81,146	102,850
Derivative liabilities at fair value	0	3,125
Total current liabilities	2,141,037	134,797
Long-term debt	0	1,988,946
Partnership liability	91,956	126,132
Asset retirement obligations	104,049	106,256
Derivative liabilities at fair value	0	323
Other liabilities	15,131	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 187,802,994 and 183,994,879 shares issued, respectively	1,878	1,840
Additional paid in capital	781,669	770,092
Treasury stock of 7,444,372 and 6,698,640 shares, respectively	-53,810	-51,422
Accumulated other comprehensive income	71,853	109,881
Retained deficit	-1,939,461	-1,836,361
Total stockholders' equity	-1,137,871	-1,005,970
Total liabilities and stockholders' equity	$1,214,302	$1,369,726

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]
Unevaluated costs of oil and natural gas properties	$18,803	$221,605
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	187,802,994	183,994,879
Treasury stock, shares	7,444,372	6,698,640

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, 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
Net income (loss)	-103,100					-103,100	-103,100
Hedge settlements reclassified into earnings from AOCI, net of income tax					24,702		24,702
Net change in derivative fair value, net of income tax	0
Foreign currency translation adjustment	-13,326				-13,326		-13,326
Issuance & vesting of stock compensation		-38	-11,577	2,388			-9,227
Balances at Dec. 31, 2014		$1,878	$781,669	($53,810)	$71,853	($1,939,461)	($1,137,871)

Consolidated_Statements_Of_Equ1

Consolidated Statements Of Equity (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Income tax effect related to hedge derivative contract settlements reclassified into earnings from accumulated other comprehensive income	$11,318	$21,581	$66,417
Income tax effect related to net change in derivative fair value	$0	$0	$36,206

Consolidated_Statements_Of_Cas

Consolidated Statements Of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Proceeds from Crestwood earn-out			$41,097
Operating activities:
Net income (loss)	-103,100	161,618	-2,352,606
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depletion, depreciation and accretion	61,126	62,612	163,624
Impairment expense	71,988	1,863	2,625,928
Write-off of MLP related fees and expenses	0	0	7,505
Deferred income tax expense (benefit)	11,318	21,581	-289,981
Non-cash (gain) loss from hedging and derivative activities	-61,654	3,904	57,826
Stock-based compensation	11,616	17,979	22,246
Non-cash interest expense	11,198	26,920	9,854
Fortune Creek accretion	15,067	19,245	19,472
Other	7,533	6,783	1,037
Changes in assets and liabilities
Accounts receivable	-7,141	-3,994	30,950
Other assets	43	322	-4,435
Accounts payable	-358	-7,133	-8,895
Income taxes	-668	7,828	1,183
Accrued and other liabilities	-24,597	-31,900	-14,884
Net cash provided by (used in) operating activities	-7,629	-51,700	227,727
Investing activities:
Capital expenditures	-133,481	-101,288	-485,479
Proceeds from sale of properties and equipment	3,222	7,171	72,725
Purchases of marketable securities	-55,890	-213,738	0
Maturities and sales of marketable securities	222,025	47,603	0
Net cash provided by (used in) investing activities	131,463	246,044	-371,657
Financing activities:
Issuance of debt	243,184	1,237,352	467,959
Repayments of debt	-193,689	-1,308,382	-310,430
Debt issuance costs paid	-1,705	-26,296	-3,022
Distribution of Fortune Creek Partnership funds	-39,993	-14,965	-14,285
Proceeds from exercise of stock options	0	0	11
Purchase of treasury stock	-2,388	-1,927	-3,144
Net cash provided by (used in) financing activities	5,409	-114,218	137,089
Effect of exchange rate changes in cash	5,183	4,026	-1,354
Net change in cash and cash equivalents	134,426	84,152	-8,195
Cash and cash equivalents at beginning of period	89,103	4,951	13,146
Cash and cash equivalents at end of period	223,529	89,103	4,951
Synergy [Member]
Investing activities:
Proceeds from Southwestern Transaction	0	42,297	0
Proceeds from Tokyo Gas Transaction	0	42,297	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	42,297	0
Tokyo Gas [Member]
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Gain on Tokyo Gas Transaction	0	-339,328	0
Investing activities:
Proceeds from Southwestern Transaction	0	463,999	0
Proceeds from Tokyo Gas Transaction	0	463,999	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,999	0
kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out	0	0	41,097
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Crestwood earn-out	0	0	-41,097
Sandwash Basin [Member]
Investing activities:
Proceeds from Southwestern Transaction	95,587	0	0
Proceeds from Tokyo Gas Transaction	95,587	0	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	$95,587	$0	$0

Nature_Of_Operations

Nature Of Operations	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Nature Of Operations	NATURE OF OPERATIONS
	We are an independent oil and natural 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, 2014, our significant oil and natural 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 oil and natural gas, the price of foreign imports, the level of consumer demand and the price of available alternative fuels.
	During the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. During the formal marketing process, we also received additional amendments to the financial covenants to our Combined Credit Agreements. These amendments, which included the replacement of the minimum interest coverage ratio with a minimum EBITDAX requirement, provided relief from the continued pressure on our cash flows relative to our obligations, which in turn allowed time for the formal marketing process. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity.
	In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.
	Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. The Chapter 11 cases are being jointly administered for procedural purposes only by the Bankruptcy Court under the caption In re Quicksilver Resources Inc., et. al., Case No. 15-10585 (Jointly Administered).
	We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. As part of our “first day” motions in the Chapter 11 proceedings, we obtained Bankruptcy Court approval to, among other things and subject to the applicable caps contained in the orders of the Bankruptcy Court, on an interim basis, pay employee wages, health benefits and certain other employee obligations, to pay certain lienholders and critical vendors and forward funds belonging to third parties, including royalty holders and other partners. A final hearing on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties will be held on April 15, 2015.
	On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.
	For the duration of our Chapter 11 proceedings, our operations and our ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process as described in Item 1A, “Risk Factors.” As a result of these risks and uncertainties, the number of our outstanding shares and our shareholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 proceedings, and the description of our operations, properties and capital plans included in this Annual Report may not accurately reflect our operations, properties and capital plans following the Chapter 11 process.
	In particular, subject to certain exceptions, under the Bankruptcy Code, the U.S. Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the U.S. Debtors of performing their future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert claims against the applicable U.S. Debtor's estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires the U.S. Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease with the U.S. Debtor in this Annual Report, including where applicable a quantification of our obligations under any such executory contract or unexpired lease with the U.S. Debtor is qualified by any overriding rejection rights we have under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and the U.S. Debtors expressly preserve all of their rights with respect thereto.
	There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions, including a sale of all or substantially all of our assets, that satisfies the conditions of the Bankruptcy Code and, is authorized by the Bankruptcy Court.
	The above conditions represent an event of default under our long-term debt and give rise to substantial doubt as to our ability to continue as a going concern. We have classified all debt as current at December 31, 2014. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported income and expenses could be required and could be material.

Significant_Accounting_Policie

Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
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. Our Chapter 11 filing in 2015 will require us to evaluate whether we continue to control our subsidiaries and VIEs through our equity ownership. If we determine that we do not control any or all of these subsidiaries or VIEs, we will no longer consolidate those subsidiaries.
	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 2014, two purchasers individually accounted for 17% and 13% of cash collected for our production revenue. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers accounted for 21% and 15% 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.
	To the extent we enter into derivatives, these positions are 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 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.
	Property, Plant, and Equipment
	We follow the full cost method in accounting for our oil and natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural 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, which costs are assessed annually for impairment and inclusion as depletable costs in the respective cost center.
	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 natural 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 oil and natural gas 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 7 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, included in Other Current Assets, were comprised of $7.6 million and $15.8 million of materials and parts and $0.7 million and $2.5 million of NGLs as of December 31, 2014 and 2013, respectively. Inventories are primarily comprised of materials and parts including oil and natural 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 of $7.0 million and $3.0 million for 2014 and 2013, respectively, 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, 2014 and 2013, 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 within debt. 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 12 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. Losses from foreign currency transactions of $3.7 million and $2.4 million in 2014 and 2013, respectively, 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.
	We consolidate the financial position of Fortune Creek and the results of operations in our consolidated financial statements. Note 14 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 16 includes the calculation of earnings per share.
	Recently Issued Accounting Standards
	In February 2015, the FASB issued accounting guidance, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” requiring reporting entities to evaluate whether they should consolidate certain legal entities. The standard is effective for periods beginning after December 15, 2015 with early adoption permitted. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements.
	In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
	No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 Annual Report on Form 10-K.

Divestitures

Divestitures	12 Months Ended
	Dec. 31, 2014
Acquisitions And Divestitures [Abstract]
Acquisitions And Divestitures	DIVESTITURES
	In May 2014, we completed the sale of our Niobrara Asset to Southwestern. The purchase price was subject to customary purchase price adjustments, which resulted in Southwestern paying us $95.6 million. We determined that the Southwestern Transaction did not represent a significant disposal of reserves under GAAP, therefore we reduced the balance of U.S. oil and natural gas properties by the amount of these proceeds and we did not recognize a gain or loss.
	In October 2013, we executed an agreement with Eni involving our West Texas Asset 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 is responsible for 100% of the cost for drilling, completion and production facilities up to a total of $52.0 million, thereby earning a 50% interest in our acreage. Upon Eni’s fulfillment of the $52.0 million carry, which was substantially met as of the first quarter of 2015, we participate equally in the future revenue, operating costs and capital expenditures on the wells drilled and completed pursuant to the joint exploration agreement. Per the joint exploration agreement with Eni, we have the ability to decline participation in any well after the Eni carry is fulfilled, subject to non-consent payout penalties.
	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 under GAAP, therefore our U.S. oil and natural gas properties were reduced by these proceeds and we did not recognize a gain or loss.
	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 under GAAP. Our U.S. oil and natural 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 natural 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 was the operator of the majority of the jointly owned lands. Subsequently, these assets were sold in the Southwestern Transaction described above.

Derivatives_And_Fair_Value_Mea

Derivatives And Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2014			2013
		(in thousands)						(in thousands)
	Level 2 inputs	$	104,608		$	107,395		$	—		$	3,448
	Level 3 inputs	44,959			23,485			—			—
	Total	$	149,567		$	130,880		$	—		$	3,448
	The fair value of “Level 2” derivative instruments included in these disclosures was estimated using inputs quoted in active markets for the periods covered by the derivatives. 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 other 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 input is the market prices for natural gas for the period from 2019 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 $2.88 to $4.60 and are based upon prices quoted in active markets for the period of time available. A decrease of these unobservable inputs would increase the fair value, while an increase would decrease the fair value.
	The following table identifies the changes in “Level 3” net asset derivative fair values for the periods indicated:
		As of December 31,
		2014			2013
		(in thousands)
	Balance at beginning of period	$	23,485		$	(4,931	)
	Total gains (losses) for the period:
	Unrealized gain on derivatives	31,824			40,398
	Transfers out of Level 3	(3,559		)	—
	Settlements in net derivative losses	(6,791		)	(11,982		)
	Balance at end of period	$	44,959		$	23,485
	Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	32,074		$	41,909
	In 2014, transfers from Level 3 to Level 2 represent our ten-year derivative instruments that were exchanged in December 2014 for derivative instruments with shorter durations and which were valued on the date of the transfer.
	Commodity Price Derivatives
	As of December 31, 2014, we had natural gas swaps as follows:
	Production		Daily Production
	Year		Volume
			Natural Gas
			MMcfd
	2015		150
	2016-2021		30
	Between January and March 2015, substantially all of our derivatives were restructured or terminated. These restructured and terminated derivatives reduced our daily production volume of natural gas economically hedged to 20 MMcfd in 2015 and we no longer have any derivatives beyond 2015. The cash proceeds of the 2015 terminated derivatives were $135.7 million.
	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)
	2015	$	33,191
	2016	13,476
	2017	12,531
	2018	11,664
	2019 and thereafter	29,779
		$	100,641
	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 $22.4 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 2014 and 2013, we recognized $2.0 million and $12.0 million, respectively, of those deferred gains as a reduction of interest expense. The remaining $2.8 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)
	2015	$	2,194
	2016	569
		$	2,763
	Fair Value Disclosures
	The estimated fair value of all of our derivative instruments at December 31, 2014 and 2013 were as follows:
		Asset Derivatives							Liability Derivatives
		As of December 31,							As of December 31,
		2014			2013				2014			2013
		(in thousands)							(in thousands)
	Derivatives not designated as hedges:
	Commodity contracts reported in:
	Current derivative assets	$	120,176		$	60,063			$	—		$	2,540
	Noncurrent derivative assets	81,187			105,315				51,796			31,958
	Current derivative liabilities	—			—				—			3,125
	Noncurrent derivative liabilities	—			—				—			323
	Total derivatives not designated as hedges	$	201,363		$	165,378			$	51,796		$	37,946
	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, 2013 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.
	Investments
	We hold certain short-term marketable securities related to interest bearing time deposits and commercial paper. These 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. During June 2014, we sold $10.0 million and transferred $10.0 million of held-to-maturity marketable securities to available-for-sale. Proceeds from these sales were used to reduce the outstanding balance on the Combined Credit Agreements. The estimated fair value of available-for-sale marketable securities is determined using market quotations based on recent trade activity (“Level 2” inputs). At December 31, 2014 we did not own any marketable securities that were not cash equivalents. At December 31, 2013, we had the following marketable securities:
		31-Dec-13
	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
Nonrecurring Fair Value Measurements
At December 31, 2014, we impaired inventory in Canada, specifically in our Horn River Asset, to the fair value of current market prices in areas where the inventory could be used less shipping costs (“Level 3” input). As drilling activity has declined in the general area where this inventory is located, shipping costs were included in the net realizable value adjustment. For our Fortune Creek gathering system impairment, a discounted cash flow analysis considering the contractual rate under the gathering agreement and QRCI’s proved reserves (“Level 3” input) was performed to determine the net realizable value. Additionally, impairments were incurred in 2014 on buildings and surface land in the U.S. as current market prices, as indicated by broker quotes and recent sales activity (“Level 3” input), did not support our historical book value on these assets.
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, 2014 and December 31, 2013 are included in Note 10.

Accounts_Receivable

Accounts Receivable	12 Months Ended
	Dec. 31, 2014
Accounts Receivable, Net [Abstract]
Accounts Receivable	ACCOUNTS RECEIVABLE
	Accounts receivable consisted of the following:
		As of December 31,
		2014			2013
		(in thousands)
	Accrued production revenue	$	32,130		$	34,785
	Joint interest billings	22,621			15,630
	Income taxes	7,574			7,931
	Canadian value added taxes	173			60
	Other	2,937			328
	Allowance for doubtful accounts	(277		)	(89		)
		$	65,158		$	58,645

Other_Current_Assets

Other Current Assets	12 Months Ended
	Dec. 31, 2014
Other Current Assets [Abstract]
Other Current Assets	OTHER CURRENT ASSETS
	Other current assets consisted of the following:
		As of December 31,
		2014		2013
		(in thousands)
	Inventories	$	8,269	$	18,334
	Deposits	1,284		1,044
	Other prepaid expense	4,861		2,968
		$	14,414	$	22,346

Property_Plant_And_Equipment

Property, Plant And Equipment	12 Months Ended
	Dec. 31, 2014
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,
		2014				2013
		(in thousands)
	Oil and natural gas properties
	Subject to depletion	$	5,821,167			$	5,687,557
	Unevaluated costs	18,803				221,605
	Accumulated depletion	(5,225,302		)		(5,268,719		)
	Net oil and natural gas properties	614,668				640,443
	Other property and equipment
	Pipelines and processing facilities	316,013				347,093
	General properties	66,455				72,125
	Accumulated depreciation	(268,356		)		(198,856		)
	Net other property and equipment	114,112				220,362
	Property, plant and equipment, net of accumulated depletion and depreciation	$	728,780			$	860,805
	Ceiling Test Analysis and Impairment
	The charges for impairment are summarized below:
				Pre-tax Charges for Impairment
		Segment		2014				2013				2012
				(in thousands)
	U.S.
	Oil and natural gas properties	Exploration and production		$	—			$	—			$	2,152,128
	Other property and equipment	Midstream		135				54				7,328
	Other property and equipment	Exploration and production		2,450				1,809				537
	Canada
	Oil and natural gas properties	Exploration and production		—				—				465,935
	Other property and equipment	Midstream		58,360				—				—
	Other property and equipment	Exploration and production		11,043				—				—
				$	71,988			$	1,863			$	2,625,928
	In Canada during 2014, we impaired the Fortune Creek gathering system as we do not have sufficient liquidity to develop our Horn River Asset. An undiscounted cash flow analysis did not support the recoverability of the carrying value of the gathering system and a discounted cash flow analysis resulted in our recording an impairment of $58.4 million at December 31, 2014. Additionally, we impaired other property and equipment assets in our Horn River Asset at December 31, 2014 based on our inability to fund the development of our Horn River Asset.
	In the U.S., we recognized other property and equipment impairment charges in 2014 and 2013 for surface land, buildings and pipeline in Texas. During 2012 we impaired pipelines and facilities in Colorado and Texas due to reduced anticipated utilization and a compressed natural gas facility in Texas due to reduced use.
	As described in Note 2, we are required to perform a quarterly ceiling test for impairment of our oil and natural gas properties in each of our cost centers. We did not recognize impairment in 2014 and 2013 during our quarterly ceiling tests. 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 natural 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 natural gas properties, the AECO price declined 36% from the price used at December 31, 2011. In 2012, the impairment on our oil and natural 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.
	Unevaluated Oil and Natural Gas Properties Not Subject to Depletion
	Under full cost accounting, we may exclude certain unevaluated oil and natural gas property costs from the amortization base pending determination of whether proved reserves have been established or impairment has occurred. A summary of the unevaluated properties not subject to depletion at December 31, 2014 and 2013 and the year in which they were incurred follows:
		December 31, 2014 Costs Incurred During																December 31, 2013 Costs Incurred During
		2014				2013				2012				Prior		Total		2013		2012		2011		Prior		Total
		(in thousands)																(in thousands)
	U.S.
	Acquisition costs	$	5,637			$	—			$	1,574			$	9,029	$	16,240	$	—	$	3,013	$	13,484	$	—	$	16,497
	Exploration costs	—				—				—				—		—		14		364		—		—		378
	Capitalized interest	395				961				1,207				—		2,563		1,093		1,374		—		—		2,467
	Total U.S.	$	6,032			$	961			$	2,781			$	9,029	$	18,803	$	1,107	$	4,751	$	13,484	$	—	$	19,342
	Canada
	Acquisition costs	$	—			$	—			$	—			$	—	$	—	$	—	$	2,956	$	1,300	$	68,586	$	72,842
	Exploration costs	—				—				—				—		—		7,044		31,746		41,092		30,413		110,295
	Capitalized interest	—				—				—				—		—		3,947		2,724		3,522		8,933		19,126
	Total Canada	$	—			$	—			$	—			$	—	$	—	$	10,991	$	37,426	$	45,914	$	107,932	$	202,263
	Total	$	6,032			$	961			$	2,781			$	9,029	$	18,803	$	12,098	$	42,177	$	59,398	$	107,932	$	221,605
	The following table summarizes the regions where we have unevaluated oil and natural gas property costs not subject to depletion.
		As of December 31,
		2014				2013
		(in thousands)
	West Texas	$	18,803			$	19,343
	Horn River Basin	—				202,262
	Total	$	18,803			$	221,605
	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 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 terms and the renewal term of the underlying leases, which were extended in 2014.
	We continued to pursue a transaction involving our Horn River Asset in 2014, but after not reaching an agreement, we began to consider parallel marketing strategies and other strategic alternatives and, during the third quarter of 2014, we launched a formal marketing process, led by Houlihan Lokey, covering any and all of our operating assets. Bids were initially due in December 2014, but the bid deadline was subsequently extended to late January 2015. After the bid deadline passed, we evaluated the bids that were received with our advisors. Following discussions with various bidders, we concluded that the marketing process had not yet produced any viable options for asset sales or other strategic alternatives that would likely have a material impact on our capital structure or liquidity. In light of the results of our marketing efforts and our liquidity outlook, we do not have sufficient liquidity to develop the Horn River Asset. Therefore, and notwithstanding that a number of years remain under the primary lease terms, we determined to fully impair our Horn River Asset unevaluated oil and natural gas property costs to the Canadian cost center at December 31, 2014.
	Other Matters
	Capitalized overhead costs that directly relate to exploration and development activities were $11.2 million, $13.6 million and $16.8 million for 2014, 2013 and 2012, respectively. For 2014, depletion per Mcfe was $0.48 and $0.38 for the U.S. and Canada, 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. Depreciation expense was $15.2 million, $17.1 million and $18.6 million for 2014, 2013 and 2012, respectively.

Other_Assets

Other Assets	12 Months Ended
	Dec. 31, 2014
Other Assets, Noncurrent Disclosure [Abstract]
Other Assets	OTHER ASSETS
	Other assets consisted of the following:
		As of December 31,
		2014			2013
		(in thousands)
	Deferred financing costs	$	62,319		$	84,951
	Less accumulated amortization	(33,472		)	(50,171		)
	Net deferred financing costs	28,847			34,780
	Governmental and notes receivable	3,888			6,464
	Other	119			360
		$	32,854		$	41,604
	Costs related to the issuance of debt are deferred and amortized over the term of the debt.

Accrued_Liabilities

Accrued Liabilities	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities [Abstract]
Accrued Liabilities	ACCRUED LIABILITIES
	Accrued liabilities consisted of the following:
		As of December 31,
		2014		2013
		(in thousands)
	Interest payable	$	36,288	$	38,260
	Accrued operating expense	21,833		37,747
	Prepayments from partners	—		425
	Revenue payable	19,121		22,589
	Accrued state income and franchise taxes	55		1,080
	Accrued production and property taxes	677		870
	Environmental liabilities	18		36
	Accrued product purchases	310		270
	Current asset retirement obligations	967		433
	Other	1,877		1,140
		$	81,146	$	102,850

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Long-term Debt, Other Disclosures [Abstract]
Long-Term Debt	LONG-TERM DEBT
	Long-term debt consisted of the following:
		As of December 31,
		2014				2013
		(in thousands)
	Combined Credit Agreements	$	274,514			$	211,200
	Second Lien Term Loan, net of unamortized discount of $14,758 and $17,428	610,242				607,572
	Second Lien Notes due 2019, net of unamortized discount of $4,723 and $5,577	195,277				194,423
	Senior Notes due 2015, net of unamortized discount of $0 and $2,149	—				10,472
	Senior Notes due 2016, net of unamortized discount of $0 and $10,825	—				8,044
	Senior Notes due 2019, net of unamortized discount of $4,081 and $5,378	293,919				293,243
	Senior Notes due 2021, net of unamortized discount of $14,410 and $15,810	310,590				309,190
	Senior Subordinated Notes due 2016	350,000				350,000
	Total debt	2,034,542				1,984,144
	Unamortized deferred gain—terminated interest rate swaps	2,763				4,802
	Current portion of long-term debt	(2,037,305		)		—
	Long-term debt	$	—			$	1,988,946
	Original maturities assuming no acceleration or springing maturity as of December 31, 2014 are as follows:
		2015				2016				2017				2018		2019		Thereafter
		(in thousands)
	Combined Credit Agreements	$	—			$	274,514			$	—			$	—	$	—	$	—
	Second Lien Term Loan	—				—				—				—		625,000		—
	Second Lien Notes due 2019	—				—				—				—		200,000		—
	Senior Notes due 2019	—				—				—				—		298,000		—
	Senior Notes due 2021	—				—				—				—		—		325,000
	Senior Subordinated Notes due 2016	—				350,000				—				—		—		—
	Total Indebtedness	$	—			$	624,514			$	—			$	—	$	1,123,000	$	325,000
	In February 2015, in light of (a) not yet having identified a transaction that would have a material impact on our capital structure or liquidity, (b) the potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, and (c) other potential defaults, we elected not to make the approximately $13.6 million interest payment on our Senior Notes due 2019, which was due on February 17, 2015. During the 30-day grace period provided for in the Senior Notes due 2019 Indenture, we continued discussions with our creditors. The discussions with our creditors did not produce an agreement that would enable us to effectively address, in a holistic manner, the impending issues adversely impacting our business, including (i) potential springing maturities under our Combined Credit Agreements, the Second Lien Term Loan and the Second Lien Notes, (ii) potential near-term liquidity shortfalls due to the springing maturities, (iii) potential near-term breaches of certain financial covenants resulting from sharp declines in natural gas and NGL prices, and (iv) certain other potential defaults under our Combined Credit Agreements and the Second Lien Term Loan.
	Accordingly, on March 17, 2015, the Company and our subsidiaries Barnett Shale Operating LLC, Cowtown Drilling, Inc., Cowtown Gas Processing L.P., Cowtown Pipeline Funding, Inc., Cowtown Pipeline L.P., Cowtown Pipeline Management, Inc., Makarios Resources International Holdings LLC, Makarios Resources International Inc., QPP Holdings LLC, QPP Parent LLC, Quicksilver Production Partners GP LLC, Quicksilver Production Partners LP, and Silver Stream Pipeline Company LLC each filed a voluntary petition under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court to restructure our obligations and capital structure. Based on this subsequent event, we have classified all debt as current at December 31, 2014.
	Our Chapter 11 filings constituted an event of default under the Combined Credit Agreements and all borrowings and other fees under the Combined Credit Agreements became immediately due and payable. The ability of the lenders under the Combined Credit Agreements to seek remedies to enforce their rights under the agreements was automatically stayed as a result of the Chapter 11 filings, and the lenders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.
	On March 16, 2015, we, along with QRCI, entered into the Forbearance Agreement with the administrative agents and certain of the lenders under the Combined Credit Agreements. As a result of the Chapter 11 filing, the obligations under the Combined Credit Agreements were automatically accelerated. However, pursuant to the Forbearance Agreement, the administrative agents and the lenders agreed to, among other things, (i) forbear from exercising their rights and remedies in connection with specified defaults under the Amended and Restated Canadian Credit Facility related to our Chapter 11 filing until the earlier of June 16, 2015 or certain other events specified in the Forbearance Agreement, including, among other things, the commencement by QRCI or certain specified Canadian subsidiary guarantors of insolvency proceedings and (ii) waive compliance with certain specified terms and conditions relating to the renewal of outstanding evergreen letters of credit under the Combined Credit Agreements.
	Our Chapter 11 filings also constituted an event of default under the Second Lien Term Loan, the Second Lien Notes, the Senior Notes due 2019, the Senior Notes due 2021, and the Senior Subordinated Notes. All principal, interest and other amounts under each of these debt instruments became immediately due and payable. The ability of the lenders and noteholders to seek remedies to enforce their rights under the applicable debt instruments was automatically stayed as a result of the Chapter 11 filings, and the lenders’ and noteholders’ rights of enforcement are subject to the applicable provisions of the Bankruptcy Code.
	Our failure to make the interest payment on our Senior Notes due 2019 within the 30-day grace period described above would have resulted in an event of default, permitting the trustee or holders of at least 25% of the aggregate principal amount outstanding of the Senior Notes due 2019 to declare the principal and accrued interest for all the Senior Notes due 2019 due and payable immediately, which in turn would have resulted in defaults under the terms of our other indebtedness.
	Combined Credit Agreements
	The Combined Credit Agreements’ global borrowing base was $325 million and the global letter of credit capacity was $280 million as of December 31, 2014. At December 31, 2014, we had $9.2 million available under the Combined Credit Agreements, all of which could be used for letters of credit. On March 17, 2015, we repaid $36.7 million of amounts outstanding under our Combined Credit Agreements from proceeds of derivative terminations. We expect to use the remaining cash proceeds from recently terminated derivatives to pay down our Combined Credit Agreements.
	In 2014, the Combined Credit Agreements' global borrowing base was reaffirmed at $325 million and the Combined Credit Agreements were amended to eliminate the requirement to meet the minimum interest coverage ratio covenant beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015. A minimum EBITDAX covenant, as defined in our Combined Credit Agreement, was added beginning in the fourth quarter of 2014 through and including the fourth quarter of 2015 that requires the following minimum EBITDAX levels:
		Minimum EBITDAX Covenant
		(in millions)
	Three months ending December 31, 2014	$	30
	Six months ending March 31, 2015	59
	Nine months ending June 30, 2015	87.25
	Twelve months ending September 30, 2015	120.5
	Twelve months ending December 31, 2015	122
	Additionally, the Combined Credit Agreements were amended changing certain definitions that impact the calculation of EBITDAX and we permanently reduced the aggregate maximum credit amounts under the Combined Credit Agreements from $1.75 billion to $450 million.
	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.
	In April 2014, we redeemed all remaining outstanding Senior Notes due 2015 at 101.938% of the principal amount plus accrued and unpaid interest representing a total payment of $10.9 million.
	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.
	In April 2014, we redeemed all remaining outstanding Senior Notes due 2016 at 105.875% of the principal amount plus accrued and unpaid interest representing a total payment of $8.9 million.
	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, 2014, 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 retained a portion of the cash received from our asset sales. Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.
Springing Maturities
As of December 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.
Interest Expense
Interest expense was $163.3 million and $251.8 million, net of capitalized interest of $5.7 million and $7.7 million, for the years ended December 31, 2014 and 2013, respectively.
Summary of All Outstanding Debt
The following table summarizes certain significant aspects of our long-term debt outstanding at December 31, 2014:
		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		2019		2021		Senior
		Agreements						Senior Notes		Senior Notes		Subordinated Notes
Principal amount (1)(2)		$325 million		$625 million		$200 million		$298 million		$325 million		$350 million
Scheduled maturity date (3)		September 6, 2016		June 21, 2019		June 21, 2019		August 15, 2019		July 1, 2021		April 1, 2016
Springing maturity date (3)		2-Oct-15		1-Jan-16		1-Jan-16		N/A		N/A		N/A
Interest rate on outstanding borrowings at December 31, 2014 (4)		4.10%		7.00%		7.00%		9.13%		11.00%		7.12%
Base interest rate options (5)(6)		LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%		LIBOR floor of 1.25%		N/A		N/A		N/A
Financial covenants (7)(9)		- Minimum current ratio of 1.0		N/A		N/A		N/A		N/A		N/A
		- Minimum EBITDAX or EBITDA to cash interest expense
		- Maximum senior secured debt leverage ratio of 2.0
Significant restrictive covenants (8)(9)		- Incurrence of debt		- Incurrence of debt		- Incurrence of debt		- 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 (9)		Any time		Any time, subject to re-pricing event		Any time, subject to re-pricing event		August 15,		July 1,		Any time
				June 21, 2015: 101		June 21, 2015: 101		2014: 104.563		2019: 102.000
								2015: 103.042		2020: par
								2016: 101.521
								2017: par
Make-whole redemption (9)		N/A		N/A		N/A		N/A		Callable prior to		N/A
										July 1, 2019 at
										make-whole call price
										of Treasury +50 bps
Change of control (9)		Event of default		Put at 101% of		Put at 101% of		Put at 101% of		Put at 101% of		Put at 101% of
				principal plus accrued		principal plus accrued		principal plus accrued		principal plus accrued		principal plus accrued
				interest		interest		interest		interest		interest
Equity clawback (9)		N/A		N/A		N/A		N/A		Redeemable until		N/A
										July 1, 2016 at
										111.00%, plus accrued
										interest for up to 35%
Estimated fair value (10)		$274.5 million		$465.6 million		$149.0 million		$74.8 million		$87.9 million		$26.5 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 natural 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 natural 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, 2014.
-3	The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 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 Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of December 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.
-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%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate of ABR plus the applicable margin.
-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%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate for Canadian dollar denominated borrowings of Canadian prime plus the default rate plus the applicable margin and for U.S. dollar denominated borrowings, U.S. prime plus the default rate plus the applicable margin.
-7	As of December 31, 2014, the minimum EBITDAX covenant for the Combined Credit Agreements is as follows:
	Minimum EBITDAX Covenant
	(in millions)
Three months ending December 31, 2014	$	30
Six months ending March 31, 2015	59
Nine months ending June 30, 2015	87.25
Twelve months ending September 30, 2015	120.5
Twelve months ending December 31, 2015	122
The minimum required interest coverage ratio for the Combined Credit Agreements for first quarter of 2016 and second quarter of 2016 is 1.50 and 2.00, respectively.
(8)	Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.
(9)	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.
(10)	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 and a first priority lien to have a fair value equal to their carrying value (“Level 1” input).
Quicksilver Resources Inc. and its Restricted Subsidiaries
The following tables, required under our indentures, provide information about Quicksilver Resources Inc. and the entities designated as restricted subsidiaries under the indentures for our Second Lien Notes, Senior Notes and Senior Subordinated Notes. Eliminations between Quicksilver Resources Inc., the related restricted guarantor subsidiaries and restricted non-guarantor subsidiaries are included in the tables below as necessary.
Condensed Consolidating Balance Sheets
	December 31,
	2014				2013
	(in thousands)
ASSETS
Current assets	$	421,533			$	393,713
Property and equipment	715,931				779,173
Investment in subsidiaries (equity method)	(82,360		)		(33,840		)
Other assets	62,245				114,961
Total assets	$	1,117,349			$	1,254,007
LIABILITIES AND EQUITY
Current liabilities	2,137,532				134,010
Long-term liabilities	117,688				2,113,221
Stockholders’ equity	(1,137,871		)		(993,224		)
Total liabilities and equity	$	1,117,349			$	1,254,007
Condensed Consolidating Statements of Income
	For the Year Ended
	2014				2013				2012
	(in thousands)
Revenue	$	569,428			$	561,562			$	709,038
Operating expenses	434,998				448,802				3,222,595
Tokyo Gas Transaction gain	—				339,328				—
Crestwood earn-out	—				—				41,097
Equity in net earnings of subsidiaries	(64,056		)		(6,682		)		(12,747		)
Operating income (loss)	70,374				445,406				(2,485,207		)
Interest expense and other	(169,874		)		(269,238		)		(162,991		)
Income tax (expense) benefit	(3,600		)		(14,550		)		295,592
Net income (loss)	$	(103,100	)		$	161,618			$	(2,352,606	)
Other comprehensive loss	(38,028		)		(51,612		)		(53,365		)
Comprehensive income (loss)	$	(141,128	)		$	110,006			$	(2,405,971	)
Condensed Consolidating Statements of Cash Flow
	For the Year Ended
	2014				2013				2012
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(13,614	)		$	(62,131	)		$	213,280
Capital expenditures	(133,481		)		(100,783		)		(474,748		)
Investment in subsidiary	(26,395		)		—				—
Proceeds from Southwestern Transaction	95,587				—				—
Proceeds from Tokyo Gas Transaction	—				463,999				—
Proceeds from Synergy Transaction	—				42,297				—
Proceeds from Crestwood earn-out	—				—				41,097
Proceeds from sale of properties and equipment	3,222				7,171				72,725
Purchases of marketable securities	(55,890		)		(213,738		)		—
Maturities and sales of marketable securities	222,025				47,603				—
Net cash flow provided by (used in) investing activities	105,068				246,549				(360,926		)
Issuance of debt	243,184				1,237,352				467,959
Repayments of debt	(193,689		)		(1,308,382		)		(310,430		)
Debt issuance costs paid	(1,705		)		(26,296		)		(3,022		)
Proceeds from exercise of stock options	—				—				11
Purchase of treasury stock	(2,388		)		(1,927		)		(3,144		)
Net cash flow provided by (used in) financing activities	45,402				(99,253		)		151,374
Effect of exchange rates on cash	(3,046		)		(1,755		)		527
Net increase in cash and equivalents	133,810				83,410				4,255
Cash and equivalents at beginning of period	88,028				4,618				363
Cash and equivalents at end of period	$	221,838			$	88,028			$	4,618

Asset_Retirement_Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2014
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, 2013 through December 31, 2014.
		As of December 31,
		2014			2013
		(in thousands)
	Beginning asset retirement obligations	$	106,689		$	116,526
	Additional liability incurred	269			3,922
	Change in estimates	(229		)	7,582
	Accretion expense	5,618			5,109
	Asset retirement costs incurred	(388		)	(1,560		)
	Settlement of liability in excess of obligation recorded	146			742
	Disposition	(1,778		)	(21,935		)
	Currency translation adjustment	(5,311		)	(3,697		)
	Ending asset retirement obligations	105,016			106,689
	Less current portion	(967		)	(433		)
	Long-term asset retirement obligation	$	104,049		$	106,256

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
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, 2014 and 2013 are as follows:
		As of December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Property, plant and equipment	$	148,360			$	209,134
	Net operating loss carry-forwards	289,261				183,982
	Investment in Fortune Creek	3,763				3,763
	AMT tax credit	40,309				47,883
	Settlements of interest rate swaps	967				1,681
	Deferred compensation expense	11,087				11,711
	State	2,048				3,680
	Other	421				791
	Deferred tax assets	496,216				462,625
	Deferred tax liabilities:
	Net derivative gains	(61,638		)		(44,039		)
	Other	(470		)		(991		)
	Deferred tax liabilities	(62,108		)		(45,030		)
	Net deferred tax asset (liability)	434,108				417,595
	Valuation allowance	(434,108		)		(417,595		)
	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 2014, 2013 and 2012 are as follows:
		2014				2013				2012
						(in thousands)
	U.S.	$	(41,865	)		$	184,034			$	(2,142,730	)
	Canada	(57,635		)		(7,866		)		(505,446		)
	Total	$	(99,500	)		$	176,168			$	(2,648,176	)
	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. In 2012, we utilized a rate of 25.0% in Canada, while our U.S. federal and state rates were consistent with our 2013 and beyond rates.
	The components of income tax expense for 2014, 2013 and 2012 are as follows:
		2014				2013				2012
						(in thousands)
	Current state income tax expense (benefit)	$	(144	)		$	900			$	1,752
	Current U.S. federal income tax benefit	(7,574		)		(7,931		)		—
	Current Canadian income tax expense	559				—				—
	Total current income tax expense (benefit)	(7,159		)		(7,031		)		1,752
	Deferred U.S. federal income tax expense (benefit)	(11,238		)		205,820				(763,639		)
	U.S. federal valuation allowance expense	21,011				(186,713		)		533,974
	Deferred state income tax expense (benefit)	1,632				(3,680		)		—
	State valuation allowance expense	(1,632		)		3,680				—
	Deferred Canadian income tax expense (benefit)	3,620				827				(128,982		)
	Canadian valuation allowance expense	(2,634		)		1,647				61,325
	Total deferred income tax expense (benefit)	10,759				21,581				(297,322		)
	Total income tax expense (benefit)	$	3,600			$	14,550			$	(295,570	)
	The following table reconciles the statutory federal income tax rate to the effective tax rate for 2014, 2013 and 2012:
		2014			2013			2012
	U.S. federal statutory tax rate	35	%		35	%		35	%
	Permanent differences	(27.05	)%		4.8	%		(0.06	)%
	State income taxes net of federal deduction	0.09	%		0.31	%		(0.04	)%
	Canadian income taxes	1.4	%		(0.26	)%		(1.93	)%
	Other	(0.30	)%		(0.15	)%		0.67	%
	Derivatives deferred in OCI	(11.07	)%		12.43	%		—	%
	AMT NOL refund	7.61	%		—	%		—	%
	Valuation allowance	(9.30	)%		(43.87	)%		(22.48	)%
	Effective income tax rate	(3.62	)%		8.26	%		11.16	%
	As of December 31, 2013, we had net operating tax loss carry-forwards for federal tax purposes of $529 million. During the year ended December 31, 2014, we generated additional net operating losses of $283 million. The total $812 million is included in deferred tax assets, and will expire between 2029 and 2034. The net operating loss carry-forwards can be used to offset future taxable income. As of December 31, 2014, we have $40 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 2014 is principally composed of the reversal in 2014 of deferred tax liabilities related to hedging in other comprehensive income that had previously reduced the valuation allowance necessary. During 2014, we increased the U.S. federal deferred tax asset and corresponding valuation allowance by $21.0 million. The U.S. state valuation allowance decreased by $1.6 million. The Canadian valuation allowance decreased by $2.6 million. Additionally, our tax 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. We have a full valuation allowance of $3.7 million for all periods shown 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 open audits for tax years 2010 and 2012. Tax years after December 31, 2009 remain subject to audit by the IRS.
	We have no unrecognized tax benefits for 2013 or 2014.

Commitments_And_Contingencies

Commitments And Contingencies	12 Months Ended
	Dec. 31, 2014
Loss Contingency [Abstract]
Commitments And Contingencies	COMMITMENTS AND CONTINGENCIES
	Contractual Obligations
	Information regarding our contractual obligations, at December 31, 2014, is set forth in the following table:
		GPT		Drilling Rig		Operating		Purchase
		Contracts (1)		Contracts (2)		Leases (3)		Obligations (4)
		(in thousands)
	2015	$	72,995	$	6,577	$	4,181	$	220
	2016	69,566		—		4,275		—
	2017	66,492		—		4,098		—
	2018	60,453		—		3,961		—
	2019	44,241		—		4,001		—
	Thereafter	95,250		—		8,849		—
	Total	$	408,997	$	6,577	$	29,365	$	220
	(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 unused firm capacity rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts. As described below, this amount includes an amount we expect the service provider will claim to be entitled to with respect to QRCI's gathering and processing contract as of December 31, 2014. As further described below, the contract was terminated in March 2015 and we expect that we and the third party will disagree regarding the remaining amounts payable under the contract.
	(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 ranging from $23,000 to $24,300 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 $3.5 million in 2014, $3.6 million in 2013 and $4.2 million in 2012. Minimum payments have not been reduced by minimum sublease rentals of $1.6 million due in the future under noncancelable subleases.
	(4)	At December 31, 2014, we were under contract to purchase goods and services.
	Commitments and Contingencies
	At December 31, 2014, we had $6.4 million in surety bonds issued to fulfill contractual, legal or regulatory requirements and $41.3 million in letters of credit outstanding against the credit facility. Surety bonds and letters of credit generally have an annual renewal option.
	QRCI did not pay an uneconomic Canadian gathering and processing commitment, which included significant unused firm capacity, due in late February 2015. In early March 2015, the third party service provider issued a demand letter regarding the missed payment and suspended service resulting in our production in our Horn River Asset being shut-in. Further, a termination notice was issued effective March 19, 2015. We are exploring alternatives to gather and process our Horn River Asset production; however, we may not be able to find economic alternatives in the near-term, or at all.
	In connection with this Canadian gathering and processing contract, we had previously issued a letter of credit in the amount of C$33 million. Upon termination, the third party drew down the full face amount of the letter of credit. We do not believe the third party was legally entitled to draw down the entire amount of the letter of credit and we have reserved all of our rights, entitlements and remedies in that regard.
	We expect that we and the third party will disagree as to what are the remaining obligations under the relevant agreement and the length of the remaining term of the agreement and as to the remedies and defenses available to the parties. While we expect to vigorously dispute the amount, we expect that the third party will claim to be entitled to up to approximately C$126 million (including the proceeds of the letter of credit) as the aggregate of the monthly tolls for firm capacity for the alleged remainder of the term of the relevant agreement.
	As a result of our partial working interest sale to Eni in 2009, we entered into a joint development agreement with Eni in our Barnett Shale Asset. 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 each of July 2011 and June 2012, we received a subpoena duces tecum from the SEC requesting certain documents. In July 2014, the SEC notified us that the staff has completed its investigation and does not intend to recommend an enforcement action by the SEC against us.
	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, 2014, we had recorded less than $0.1 million for liabilities for environmental matters.

Fortune_Creek

Fortune Creek	12 Months Ended
	Dec. 31, 2014
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 C$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 C$180 million as of December 31, 2014. The costs to be incurred under the spending requirement generally reflect the capital expenditures of all working interests in the well for wells in which we have a working interest regardless of our working interest percentage. 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 would reduce, by an equal amount, our cash payments under the gathering agreement in the final months of its initial term and would also reduce the balance of the Partnership Liability as presented on the consolidated balance sheet. 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 C$0.13 per Mcf until at least 2016. We are required to purchase equipment used by Fortune Creek, at our election, in either January 2016 or May 2018 at a price of C$33 million. We do not expect to be able to satisfy these capital expenditure requirements or equipment purchases with our cash on hand, committed financing or cash flow from operations and will need to obtain additional debt or equity financing or sell assets, which we may not be able to do on satisfactory terms, or at all.
	We committed gas production from our Horn River Asset for ten years beginning 2012, as more fully described below. KKR contributed C$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 or the cash penalty under the minimum capital expenditure, KKR has the right to liquidate the partnership and could assert a guarantee claim against us. 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 17 contains financial information for Fortune Creek in our condensed consolidating financial statements. Note 7 contains information about our impairment of the Fortune Creek gathering system.

Quicksilver_Stockholders_Equit

Quicksilver Stockholders' Equity	12 Months Ended
	Dec. 31, 2014
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, 2014, we had 180.4 million shares of common stock outstanding.
	The following table shows common share and treasury share activity since January 1, 2012:
		Common			Treasury
		Shares Issued			Shares Held
	Balance at January 1, 2012	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
	Stock options exercised	—			—
	Restricted stock activity	3,808,115			745,732
	Balance at December 31, 2014	187,802,994			7,444,372
	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 25% of our common stock at March 17, 2015, 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, 2014 and 2013, 11.6 million shares and 15.4 million shares, respectively, were available for issuance under the 2006 Equity Plan.
	Stock Options
	No options were granted during 2014. The following summarizes the values from and assumptions for the Black-Scholes option pricing model for stock options issued during 2013 and 2012:
		2013		2012
	Weighted average grant date fair value	$1.05		$4.21
	Weighted average risk-free interest rate	1.31%		1.14%
	Expected life	4.9 years		6.0 years
	Weighted average volatility	68.97%		68.20%
	Expected dividends	—		—
	The following table summarizes our stock option activity for 2014:
		Shares			Weighted Average Exercise Price		Weighted Average Remaining Contractual Life		Aggregate Intrinsic Value
							(in years)		(in thousands)
	Outstanding at January 1, 2014	6,771,578			$	7.82
	Forfeited	(60,939	)		3.04
	Expired	(119,866	)		9.8
	Outstanding at December 31, 2014	6,590,773			$	7.83	5.1		$	—
	Exercisable at December 31, 2014	5,224,531			$	9.18	4.3		$	—
	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 $8.07 and a weighted average remaining contractual life of 5.0 years.
	As of December 31, 2014 the unrecognized compensation cost related to outstanding unvested options was $0.5 million, which is expected to be recognized in expense through August 2016. Compensation expense related to stock options of $1.4 million, $3.9 million and $7.4 million was recognized for 2014, 2013 and 2012, respectively. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2014 and 2013 was $0.4 million and $1.3 million, respectively. The total intrinsic value of options exercised during 2012 was $0.1 million. No options were exercised in 2014 and 2013.
	Restricted Stock and Stock Units
	The following table summarizes our restricted stock and stock unit activity for 2014:
		Payable in shares					Payable in cash
		Shares			Weighted		Shares			Weighted
					Average					Average
					Grant Date					Grant Date
					Fair Value					Fair Value
	Outstanding at January 1, 2014	5,668,090			$	3.9	1,572,341			$	3.69
	Granted	6,070,563			2.19		—			—
	Vested	(2,559,959	)		4.86		(636,146	)		4.27
	Forfeited	(1,122,429	)		2.26		(72,220	)		3.28
	Outstanding at December 31, 2014	8,056,265			$	2.54	863,975			$	3.33
	As of December 31, 2014, the unrecognized compensation cost related to outstanding unvested restricted stock and RSUs was $11.7 million, which is expected to be recognized through December 2016. Grants of restricted stock and RSUs during 2014 had an estimated grant date fair value of $13.3 million. The fair value of RSUs to be settled in cash was $0.2 million and $4.8 million during 2014 and 2013, respectively. For 2014, 2013 and 2012, compensation expense related to restricted stock and RSUs of $10.5 million, $16.8 million and $15.7 million, respectively, was recognized. The income tax benefit recognized in income, prior to any tax valuation allowance consideration, related to this compensation expense during 2014 and 2013 was $3.2 million and $5.2 million, respectively. The total fair value of shares vested during 2014, 2013 and 2012 was $10.2 million, $7.1 million and $16.3 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, 2014, AOCI included $69.8 million, net of tax, and $2.1 million for derivatives and foreign currency translation, respectively. At December 31, 2013, AOCI included $94.5 million, net of tax, and $15.4 million for derivatives and foreign currency translation, respectively.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2012
		(in thousands, except per share data)
	Net income (loss) attributable to Quicksilver	$	(103,100	)	$	161,618		$	(2,352,606	)
	Basic income allocable to participating securities (1)	—			(4,252		)	—
	Income (loss) available to shareholders	$	(103,100	)	$	157,366		$	(2,352,606	)
	Weighted average common shares – basic	173,822			171,518			170,106
	Effect of dilutive securities (2)
	Share-based compensation awards	—			141			—
	Weighted average common shares — diluted	173,822			171,659			170,106
	Earnings (loss) per common share — basic	$	(0.59	)	$	0.92		$	(13.83	)
	Earnings (loss) per common share — diluted	$	(0.59	)	$	0.92		$	(13.83	)
	(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 2014, 6.6 million shares associated with our stock options and 1.0 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. 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.

Condensed_Consolidating_Financ

Condensed Consolidating Financial Information	12 Months Ended
	Dec. 31, 2014
Condensed Consolidating Financial Information [Abstract]
Condensed Consolidating Financial Information	CONDENSED CONSOLIDATING FINANCIAL INFORMATION
	The following tables provide information about the entities that guarantee our Second Lien Notes, 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 our Second Lien Notes, Senior Notes and our Senior Subordinated Notes distinguish between “restricted” subsidiaries and “unrestricted” subsidiaries. The following table illustrates our subsidiaries and their status pursuant to the Second Lien Notes, 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
	Cowtown Pipeline Management, Inc.		Cowtown Drilling Inc. (1)		1622834 Alberta Inc.
	Cowtown Pipeline L.P.		Quicksilver Resources Partners Operating Ltd. (2)		Makarios Midstream Inc.
	Cowtown Gas Processing L.P.		0942065 B.C. Ltd. (2)		Makarios Resources International Inc.
	Barnett Shale Operating LLC		0942069 B.C Ltd. (2)		Quicksilver Production Partners GP LLC
	QPP Parent LLC (2)				Quicksilver Production Partners LP
	QPP Holdings LLC (2)
	Silver Stream Pipeline Company LLC (2)
	-1	This entity was inactive for the three-year period ended December 31, 2014.
	(2)	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 Second Lien Notes, 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 terms of the indentures include customary release provisions providing that a subsidiary guarantor will be released from its obligations under a subsidiary guarantee automatically:
	•	upon the sale, disposition or other transfer (other than by lease) of (i) the capital stock of such subsidiary following which such subsidiary guarantor is no longer a subsidiary of us or (ii) all or substantially all the assets of the applicable subsidiary guarantor, in each case, to a person that is not us or a restricted subsidiary of us, provided that such sale, disposition or other transfer is made in compliance with the applicable provisions of the indentures and all of the obligations of the subsidiary guarantor under any credit facility and related documentation or other agreement relating to other indebtedness of us or our restricted subsidiaries terminates upon the consummation of such transaction; or
	•	if we designate any restricted subsidiary that is a subsidiary guarantor as an unrestricted subsidiary in accordance with the applicable provisions of the indentures.
	In addition, the obligations of each subsidiary guarantor under its subsidiary guarantee are designed to be limited as necessary to prevent that subsidiary guarantee from constituting a fraudulent conveyance under applicable bankruptcy, insolvency, reorganization or similar laws and, therefore, such subsidiary guarantee is specifically limited to an amount that such subsidiary guarantor could guarantee without such subsidiary guarantee constituting a fraudulent conveyance.
	Under the terms of the indentures, restricted guarantor subsidiaries, which fully and unconditionally and jointly and severally guarantee our obligations under the Second Lien Notes, Senior Notes or the Senior Subordinated Notes, do not include restricted subsidiaries that are (i) foreign subsidiaries, or those subsidiaries that are not organized under the laws of the United States of America or any state thereof or the District of Columbia (and any subsidiary of such a subsidiary) and (ii) any subsidiary that is not a wholly-owned subsidiary that (1) is classified as a pass-through entity for U.S. federal, state, local and foreign income tax purposes and (2) has no indebtedness.
	The following tables present financial information about Quicksilver and our restricted subsidiaries for the annual periods covered by the consolidated financial statements. Under the indentures, 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-14
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	ASSETS
	Current assets	$	774,287			$	13,909		$	68,513		$	82		$	1,742		$	(435,256	)	$	423,277
	Property and equipment	420,744				14,357			280,830			—			12,849			—			728,780
	Investment in subsidiaries (equity method)	(293,312		)		—			(82,360		)	(82,379		)	—			458,051			—
	Other assets	43,533				—			18,712			—			—			—			62,245
	Total assets	$	945,252			$	28,266		$	285,695		$	(82,297	)	$	14,591		$	22,795		$	1,214,302
	LIABILITIES AND EQUITY
	Current liabilities	$	2,038,575			$	13,837		$	520,296		$	63		$	3,522		$	(435,256	)	$	2,141,037
	Long-term liabilities	44,548				15,131			58,009			—			1,492			91,956			211,136
	Stockholders’ equity	(1,137,871		)		(702		)	(292,610		)	(82,360		)	9,577			366,095			(1,137,871		)
	Total liabilities and equity	$	945,252			$	28,266		$	285,695		$	(82,297	)	$	14,591		$	22,795		$	1,214,302
		31-Dec-13
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	ASSETS
	Current assets	$	349,586			$	10,735		$	53,034		$	909		$	1,110		$	(21,414	)	$	393,960
	Property and equipment	455,822				15,486			307,865			—			81,632			—			860,805
	Investment in subsidiaries (equity method)	(217,852		)		—			(33,840		)	(33,840		)	—			285,532			—
	Other assets	472,792				—			32,892			—			—			(390,723		)	114,961
	Total assets	$	1,060,348			$	26,221		$	359,951		$	(32,931	)	$	82,742		$	(126,605	)	$	1,369,726
	LIABILITIES AND EQUITY
	Current liabilities	$	124,275			$	12,210		$	17,167		$	888		$	1,671		$	(21,414	)	$	134,797
	Long-term liabilities	1,942,043				19,242			542,659			—			1,546			(264,591		)	2,240,899
	Stockholders’ equity	(1,005,970		)		(5,231		)	(199,875		)	(33,819		)	79,525			159,400			(1,005,970		)
Total liabilities and equity	$	1,060,348			$	26,221		$	359,951		$	(32,931	)	$	82,742		$	(126,605	)	$	1,369,726
Condensed Consolidating Statements of Income
	For the Year Ended December 31, 2014
	Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
	Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																				Consolidated
	(in thousands)
Revenue	$	410,455			$	5,730		$	153,243		$	—		$	17,585		$	(17,585	)	$	569,428
Operating expenses	299,499				1,286			134,213			—			66,581			(17,585		)	483,994
Equity in net earnings of subsidiaries	(55,678		)		—			(64,056		)	(48,989		)	—			168,723			—
Operating income (loss)	55,278				4,444			(45,026		)	(48,989		)	(48,996		)	168,723			85,434
Fortune Creek accretion	—				—			—			—			—			(15,067		)	(15,067		)
Interest expense and other	(157,350		)		86			(12,610		)	—			7			—			(169,867		)
Income tax (expense) benefit	(2,614		)		(1,586		)	(986		)	—			—			1,586			(3,600		)
Net income (loss)	$	(104,686	)		$	2,944		$	(58,622	)	$	(48,989	)	$	(48,989	)	$	155,242		$	(103,100	)
Other comprehensive income (loss)	(31,476		)		—			(6,552		)	—			—			—			(38,028		)
Equity in OCI of subsidiaries	(6,552		)		—			—			—			—			6,552			—
Comprehensive income (loss)	$	(142,714	)		$	2,944		$	(65,174	)	$	(48,989	)	$	(48,989	)	$	161,794		$	(141,128	)
	For the Year Ended December 31, 2013
	Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
	Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																				Consolidated
	(in thousands)
Revenue	$	416,516			$	788		$	144,258		$	—		$	22,364		$	(22,364	)	$	561,562
Operating expenses	329,975				346			118,481			—			9,808			(22,364		)	436,246
Tokyo Gas Transaction gain	339,328				—			—			—			—			—			339,328
Equity in net earnings of subsidiaries	(9,896		)		—			(6,682		)	12,563			—			4,015			—
Operating income (loss)	415,973				442			19,095			12,563			12,556			4,015			464,644
Fortune Creek accretion	—				—			—			—			—			(19,245		)	(19,245		)
Interest expense and other	(242,279		)		—			(26,959		)	—			7			—			(269,231		)
Income tax expense	(12,076		)		—			(2,474		)	—			—			—			(14,550		)
Net income (loss)	$	161,618			$	442		$	(10,338	)	$	12,563		$	12,563		$	(15,230	)	$	161,618
Other comprehensive loss	(40,166		)		—			(11,446		)	—			—			—			(51,612		)
Equity in OCI of subsidiaries	(11,446		)		—			—			—			—			11,446			—
Comprehensive income (loss)	$	110,006			$	442		$	(21,784	)	$	12,563		$	12,563		$	(3,784	)	$	110,006
	For the Year Ended December 31, 2012
	Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources Inc.
	Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
	(in thousands)
Revenue	$	611,477			$	4,574		$	95,887		$	—		$	14,639		$	(17,539	)	$	709,038
Operating expenses	2,643,690				4,109			577,696			—			7,940			(17,539		)	3,215,896
Crestwood earn-out	41,097				—			—			—			—			—			41,097
Equity in net earnings of subsidiaries	(437,510		)		—			(12,747		)	6,726			—			443,531			—
Operating income (loss)	(2,428,626		)		465			(494,556		)	6,726			6,699			443,531			(2,465,761		)
Fortune Creek accretion	—				—			—			—			—			(19,472		)	(19,472		)
Interest expense and other	(152,077		)		—			(10,914		)	21			27			—			(162,943		)
Income tax (expense) benefit	228,097				(163		)	67,658			—			—			(22		)	295,570
Net income (loss)	$	(2,352,606	)		$	302		$	(437,812	)	$	6,747		$	6,726		$	424,037		$	(2,352,606	)
Other comprehensive income (loss)	(57,273		)		—			3,908			—			—			—			(53,365		)
Equity in OCI of subsidiaries	3,908				—			—			—			—			(3,908		)	—
Comprehensive income (loss)	$	(2,405,971	)		$	302		$	(433,904	)	$	6,747		$	6,726		$	420,129		$	(2,405,971	)
Condensed Consolidating Statements of Cash Flow
	For the Year Ended December 31, 2014
	Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
	Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources Inc.
	Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(43,824	)		$	(1,349	)	$	31,559		$	(2	)	$	5,987		$	—		$	(7,629	)
Capital expenditures	(102,898		)		(60		)	(30,523		)	—			—			—			(133,481		)
Investment in subsidiary	881				—			(26,395		)	(26,395		)	—			51,909			—
Proceeds from Southwestern Transaction	95,587				—			—			—			—			—			95,587
Proceeds from sale of properties and equipment	2,549				—			673			—			—			—			3,222
Purchases of marketable securities	(55,890		)		—			—			—			—			—			(55,890		)
Maturities and sales of marketable securities	222,025				—			—			—			—			—			222,025
Net cash flow provided by (used in) investing activities	162,254				(60		)	(56,245		)	(26,395		)	—			51,909			131,463
Issuance of debt	174,000				—			69,184			—			—			—			243,184
Repayments of debt	(138,651		)		—			(55,038		)	—			—			—			(193,689		)
Debt issuance costs	(1,069		)		—			(636		)	—			—			—			(1,705		)
Intercompany note	(22,559		)		—			22,559			—			—			—			—
Intercompany financing	—				1,409			(2,290		)	—			—			881			—
Contribution received	—				—			—			26,395			26,395			(52,790		)	—
Distribution of Fortune Creek Partnership funds	—				—			—			—			(39,993		)	—			(39,993		)
Purchase of treasury stock	(2,388		)		—			—			—			—			—			(2,388		)
Net cash flow provided by (used in) financing activities	9,333				1,409			33,779			26,395			(13,598		)	(51,909		)	5,409
Effect of exchange rates on cash	—				—			(3,046		)	—			8,229			—			5,183
Net increase in cash and equivalents	127,763				—			6,047			(2		)	618			—			134,426
Cash and equivalents at beginning of period	83,893				—			4,135			22			1,053			—			89,103
Cash and equivalents at end of period	$	211,656			$	—		$	10,182		$	20		$	1,671		$	—		$	223,529
	For the Year Ended December 31, 2013
	Quicksilver				Restricted			Restricted			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
	Resources				Guarantor			Non-Guarantor									Resources
	Inc.				Subsidiaries			Subsidiaries									Inc.
																	Consolidated
	(in thousands)
Net cash flow provided by (used in) operating activities	$	(82,722	)		$	—		$	20,591		$	22		$	10,409		$	(51,700	)
Capital expenditures	(67,263		)		—			(33,520		)	—			(505		)	(101,288		)
Proceeds from Tokyo Gas Transaction	463,999				—			—			—			—			463,999
Proceeds from Synergy Transaction	42,297				—			—			—			—			42,297
Proceeds from sale of properties and equipment	7,128				—			43			—			—			7,171
Purchases of marketable securities	(213,738		)		—			—			—			—			(213,738		)
Maturities and sales of marketable securities	47,603				—			—			—			—			47,603
Net cash flow provided by (used in) investing activities	280,026				—			(33,477		)	—			(505		)	246,044
Issuance of debt	1,215,266				—			22,086			—			—			1,237,352
Repayments of debt	(1,157,969		)		—			(150,413		)	—			—			(1,308,382		)
Debt issuance costs	(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		)
Net cash flow provided by (used in) financing activities	(118,029		)		—			18,776			—			(14,965		)	(114,218		)
Effect of exchange rates on cash	—				—			(1,755		)	—			5,781			4,026
Net increase in cash and equivalents	79,275				—			4,135			22			720			84,152
Cash and equivalents at beginning of period	4,618				—			—			—			333			4,951
Cash and equivalents at end of period	$	83,893			$	—		$	4,135		$	22		$	1,053		$	89,103
	For the Year Ended December 31, 2012
	Quicksilver				Restricted			Restricted			Unrestricted Non-Guarantor Subsidiaries			Fortune			Quicksilver
	Resources				Guarantor			Non-Guarantor						Creek			Resources
	Inc.				Subsidiaries			Subsidiaries									Inc.
																	Consolidated
	(in thousands)
Net cash flow provided by operating activities	$	163,353			$	656		$	49,271		$	—		$	14,447		$	227,727
Capital expenditures	(231,934		)		(656		)	(242,158		)	—			(10,731		)	(485,479		)
Proceeds from Crestwood earn-out	41,097				—			—			—			—			41,097
Proceeds from sale of properties and equipment	72,362				—			363			—			—			72,725
Net cash flow used in investing activities	(118,475		)		(656		)	(241,795		)	—			(10,731		)	(371,657		)
Issuance of debt	228,500				—			239,459			—			—			467,959
Repayments of debt	(264,018		)		—			(46,412		)	—			—			(310,430		)
Debt issuance costs	(1,972		)		—			(1,050		)	—			—			(3,022		)
Distribution of Fortune Creek Partnership funds	—				—			—			—			(14,285		)	(14,285		)
Proceeds from exercise of stock options	11				—			—			—			—			11
Purchase of treasury stock	(3,144		)		—			—			—			—			(3,144		)
Net cash flow provided by (used in) financing activities	(40,623		)		—			191,997			—			(14,285		)	137,089
Effect of exchange rates on cash	—				—			527			—			(1,881		)	(1,354		)
Net increase (decrease) in cash and equivalents	4,255				—			—			—			(12,450		)	(8,195		)
Cash and equivalents at beginning of period	363				—			—			—			12,783			13,146
Cash and equivalents at end of period	$	4,618			$	—		$	—		$	—		$	333		$	4,951

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
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 natural 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. 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)
	2014
	Revenue	$	410,444		$	150,876		$	25,693		$	—		$	(17,585	)	$	569,428
	DD&A	30,411			23,902			4,970			1,843			—			61,126
	Impairment expense	2,450			11,043			58,495			—			—			71,988
	Operating income (loss)	156,382			22,601			(44,412		)	(49,137		)	—			85,434
	Property and equipment costs incurred	100,592			27,585			86			1,127			—			129,390
	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
	Property, plant and equipment—net
	31-Dec-14	$	416,901		$	280,830		$	27,205		$	3,844		$	—		$	728,780
	31-Dec-13	451,840			306,423			97,118			5,424			—			860,805
	Total assets
	31-Dec-14	$	881,906		$	285,695		$	42,857		$	3,844		$	—		$	1,214,302
	31-Dec-13	895,388			359,951			108,963			5,424			—			1,369,726

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013		2012
		(in thousands)
	Interest, net of capitalized interest	$	152,983		$	254,901	$	154,663
	Income taxes, net	(7,051		)	833		(20,682		)
	Other significant non-cash transactions are as follows:
		Years Ended December 31,
		2014			2013		2012
		(in thousands)
	Working capital related to capital expenditures	$	4,666		$	10,324	$	10,939

Employee_Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2014
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 $1.6 million, $1.8 million and $2.3 million for 2014, 2013 and 2012, 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 2014, 2013 and 2012 was $0.6 million, $0.7 million and $0.7 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 2014, 2013 and 2012 we recognized expense of $3.9 million, $4.0 million and $5.0 million, respectively, for this plan.

Transactions_With_Related_Part

Transactions With Related Parties	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Transactions With Related Parties	TRANSACTIONS WITH RELATED PARTIES
	As of March 17, 2015, members of the Darden family and entities controlled by them beneficially owned approximately 25% of our outstanding common stock. Glenn Darden and Anne Darden Self are officers and directors of Quicksilver.
	During 2013 and 2012, we paid $0.3 million and $0.5 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.
	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 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.
	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 2014, 2013 and 2012.
	Thomas Darden, brother of Glenn Darden and Anne Darden Self, retired as an employee on December 31, 2013, and resigned from the board of directors effective September 1, 2014. During 2014, consulting fee payments of $540,000, office allowance payments of $150,000 and COBRA payments of $39,000 were made to Mr. Darden. Additionally, in accordance with the agreement related to his retirement signed in May 2013 and following the execution and non-revocation of a release agreement satisfactory to us, we paid Mr. Darden a cash bonus of $286,650 and an equity bonus in the form of 72,662 fully vested shares having a grant date fair value equal to $191,100 in March 2014.
	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. 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, 2014
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)
	2014 (1)
	Operating revenue	$	91,786		$	118,032		$	163,498	$	196,112
	Operating income (loss)	(11,054		)	13,536			64,784		18,168
	Net income (loss)	(58,833		)	(36,095		)	23,757		(31,929		)
	Basic net earnings per share	$	(0.34	)	$	(0.21	)	$	0.13	$	(0.18	)
	Diluted net earnings per share	(0.34		)	(0.21		)	0.13		(0.18		)
	2013 (2) (3) (4)
	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		)
	(1)	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
	(2)	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.
	(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 $8.0 million arising from a change to the amount of unevaluated properties allocated to TGBR.
	(4)	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.

Supplemental_Oil_and_Gas_Infor

Supplemental Oil and Gas Information (Unaudited) (Notes)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Proved oil and natural 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 2014, 2013 and 2012 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, 2014 were as follows:
		Natural Gas (MMcf)									NGL (MBbl)						Oil (MBbl)					Total (MMcfe)
		U.S.			Canada			Total			U.S.		Canada		Total		U.S.		Canada	Total		U.S.		Canada		Total
	December 31, 2011	1,828,904			330,631			2,159,535			102,145		11		102,156		3,035		—	3,035		2,459,984		330,697		2,790,681
	Revisions (3)	(910,386	)		(33,945	)		(944,331	)		(45,379	)	1		(45,378	)	(479	)	—	(479	)	(1,185,534	)	(33,939	)	(1,219,473	)
	Extensions and discoveries (2)	25,858			9			25,867			3,518		—		3,518		345		—	345		49,036		9		49,045
	Sales in place (1)	(20,616	)		—			(20,616	)		(42	)	—		(42	)	(85	)	—	(85	)	(21,378	)	—		(21,378	)
	Production	(75,712	)		(29,912	)		(105,624	)		(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)	(101,848	)	(29,924	)	(131,772	)
	31-Dec-12	848,048			266,783			1,114,831			56,173		10		56,183		2,529		—	2,529		1,200,260		266,843		1,467,103
	Revisions (3)	234,835			28,948			263,783			750		—		750		62		—	62		239,707		28,948		268,655
	Extensions and discoveries (2)	50,992			9,697			60,689			—		—		—		—		—	—		50,992		9,697		60,689
	Sales in place (4)	(257,741	)		—			(257,741	)		(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)	(356,981	)	—		(356,981	)
	Production	(51,684	)		(39,372	)		(91,056	)		(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)	(69,930	)	(39,378	)	(109,308	)
	31-Dec-13	824,450			266,056			1,090,506			39,734		9		39,743		199		—	199		1,064,048		266,110		1,330,158
	Revisions (3)	(148,359	)		42,941			(105,418	)		(3,675	)	3		(3,672	)	(14	)	—	(14	)	(170,493	)	42,959		(127,534	)
	Extensions and discoveries (2)	413			—			413			—		—		—		188		—	188		1,541		—		1,541
	Sales in place	—			—			—			—		—		—		(5	)	—	(5	)	(30	)	—		(30	)
	Production	(46,027	)		(31,169	)		(77,196	)		(2,105	)	(2	)	(2,107	)	(81	)	—	(81	)	(59,143	)	(31,181	)	(90,324	)
	31-Dec-14	630,477			277,828			908,305			33,954		10		33,964		287		—	287		835,923		277,888		1,113,811
	Proved developed reserves
	31-Dec-12	725,361			266,783			992,144			47,284		10		47,294		2,416		—	2,416		1,023,561		266,843		1,290,404
	31-Dec-13	702,147			260,159			962,306			34,603		9		34,612		139		—	139		910,599		260,213		1,170,812
	31-Dec-14	619,751			277,828			897,579			33,954		11		33,965		287		—	287		825,197		277,894		1,103,091
	Proved undeveloped reserves
	31-Dec-12	122,687			—			122,687			8,890		—		8,890		113		—	113		176,705		—		176,705
	31-Dec-13	122,303			5,896			128,199			5,131		—		5,131		60		—	60		153,449		5,896		159,345
	31-Dec-14	10,726			—			10,726			—		—		—		—		—	—		10,726		—		10,726
	(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:
	•	2014 are attributable to our West Texas Asset as we drilled in areas not previously explored;
	•	2013 are attributable to our Barnett Shale Asset; and
	•	2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed).
	Canadian extensions and discoveries for 2013 and 2012 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 49,712 MMcfe, 419,972 MMcfe and (590,064) MMcfe in 2014, 2013 and 2012, respectively, and changes in non-economic factors of (177,246) MMcfe, (151,615) MMcfe and (629,407) MMcfe in 2014, 2013 and 2012, respectively, including:
	•	In 2014, we removed proved reserves of (143) Bcfe that we were unable to develop due to constrained liquidity
	•	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: (34) Bcfe, (74) Bcfe and (291) Bcfe in 2014, 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 natural gas assets as of December 31, 2014, 2013 and 2012 were as follows:
		U.S.				Canada				Consolidated
		(in thousands)
	2014
	Proved properties	$	4,650,428			$	1,170,739			$	5,821,167
	Unevaluated properties	18,803				—				18,803
	Accumulated DD&A	(4,296,953		)		(928,349		)		(5,225,302		)
	Net capitalized costs	$	372,278			$	242,390			$	614,668
	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
	Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2014, were as follows:
		U.S.				Canada				Consolidated
		(in thousands)
	2014
Proved acreage	$	—			$	—			$	—
Unproved acreage	21,722				5,519				27,241
Development costs	78,894				22,065				100,959
Exploration costs	63				—				63
Total	$	100,679			$	27,584			$	128,263
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
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, 2014, are set forth below:
	U.S.				Canada				Consolidated
	(in thousands)
2014
Natural gas, NGL and oil revenue	$	292,388			$	132,766			$	425,154
Operating expense	146,383				84,219				230,602
Depletion expense	28,567				11,778				40,345
	117,438				36,769				154,207
Income tax expense	41,103				9,266				50,369
Results from producing activities	$	76,335			$	27,503			$	103,838
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	)
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 oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, 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 2014 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,
	2014				2013				2012
Natural gas – Henry Hub, per MMBtu	$	4.35			$	3.67			$	2.76
Natural gas – AECO, per MMBtu	4.22				2.9				2.35
Oil – WTI Cushing, per Bbl	94.99				97.18				94.71
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, including future abandonment 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 oil and natural gas 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, 2014, 2013 and 2012 was as follows:
	U.S.				Canada				Total
					(in thousands)
31-Dec-14
Future revenue	$	3,476,515			$	1,053,509			$	4,530,024
Future production costs	(1,785,208		)		(483,380		)		(2,268,588		)
Future development costs	(71,143		)		(65,703		)		(136,846		)
Future income taxes	(113,119		)		(11,017		)		(124,136		)
Future net cash flows	1,507,045				493,409				2,000,454
10% discount	(817,744		)		(194,640		)		(1,012,384		)
Standardized measure of discounted future cash flows relating to proved reserves	$	689,301			$	298,769			$	988,070
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
The standardized measure was calculated without giving consideration to any tax valuation allowance.
The primary changes in the Standardized Measure for 2014, 2013 and 2012 were as follows:
	Years Ended December 31,
	2014				2013				2012
					(in thousands)
Sales of oil and natural gas net of production costs	$	(164,436	)		$	(147,402	)		$	(149,326	)
Net changes in economic factors	304,602				326,698				(1,362,793		)
Extensions and discoveries	1,455				43,328				27,003
Development costs incurred	60,169				2,302				172,563
Changes in estimated future development costs	91,635				20,766				620,127
Purchase and sale of reserves, net	(24		)		(237,409		)		(20,529		)
Revision of estimates	(103,478		)		121,916				(1,219,609		)
Accretion of discount	75,925				50,821				196,315
Net change in income taxes	(73,637		)		(86,667		)		560,485
Change in timing and other differences	(27,189		)		13,575				156,031
Net increase (decrease)	$	165,022			$	107,928			$	(1,019,733	)
Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities [Table Text Block]
		Natural Gas (MMcf)									NGL (MBbl)						Oil (MBbl)					Total (MMcfe)
		U.S.			Canada			Total			U.S.		Canada		Total		U.S.		Canada	Total		U.S.		Canada		Total
	December 31, 2011	1,828,904			330,631			2,159,535			102,145		11		102,156		3,035		—	3,035		2,459,984		330,697		2,790,681
	Revisions (3)	(910,386	)		(33,945	)		(944,331	)		(45,379	)	1		(45,378	)	(479	)	—	(479	)	(1,185,534	)	(33,939	)	(1,219,473	)
	Extensions and discoveries (2)	25,858			9			25,867			3,518		—		3,518		345		—	345		49,036		9		49,045
	Sales in place (1)	(20,616	)		—			(20,616	)		(42	)	—		(42	)	(85	)	—	(85	)	(21,378	)	—		(21,378	)
	Production	(75,712	)		(29,912	)		(105,624	)		(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)	(101,848	)	(29,924	)	(131,772	)
	31-Dec-12	848,048			266,783			1,114,831			56,173		10		56,183		2,529		—	2,529		1,200,260		266,843		1,467,103
	Revisions (3)	234,835			28,948			263,783			750		—		750		62		—	62		239,707		28,948		268,655
	Extensions and discoveries (2)	50,992			9,697			60,689			—		—		—		—		—	—		50,992		9,697		60,689
	Sales in place (4)	(257,741	)		—			(257,741	)		(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)	(356,981	)	—		(356,981	)
	Production	(51,684	)		(39,372	)		(91,056	)		(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)	(69,930	)	(39,378	)	(109,308	)
	31-Dec-13	824,450			266,056			1,090,506			39,734		9		39,743		199		—	199		1,064,048		266,110		1,330,158
	Revisions (3)	(148,359	)		42,941			(105,418	)		(3,675	)	3		(3,672	)	(14	)	—	(14	)	(170,493	)	42,959		(127,534	)
	Extensions and discoveries (2)	413			—			413			—		—		—		188		—	188		1,541		—		1,541
	Sales in place	—			—			—			—		—		—		(5	)	—	(5	)	(30	)	—		(30	)
	Production	(46,027	)		(31,169	)		(77,196	)		(2,105	)	(2	)	(2,107	)	(81	)	—	(81	)	(59,143	)	(31,181	)	(90,324	)
	31-Dec-14	630,477			277,828			908,305			33,954		10		33,964		287		—	287		835,923		277,888		1,113,811
	Proved developed reserves
	31-Dec-12	725,361			266,783			992,144			47,284		10		47,294		2,416		—	2,416		1,023,561		266,843		1,290,404
	31-Dec-13	702,147			260,159			962,306			34,603		9		34,612		139		—	139		910,599		260,213		1,170,812
	31-Dec-14	619,751			277,828			897,579			33,954		11		33,965		287		—	287		825,197		277,894		1,103,091
	Proved undeveloped reserves
	31-Dec-12	122,687			—			122,687			8,890		—		8,890		113		—	113		176,705		—		176,705
	31-Dec-13	122,303			5,896			128,199			5,131		—		5,131		60		—	60		153,449		5,896		159,345
	31-Dec-14	10,726			—			10,726			—		—		—		—		—	—		10,726		—		10,726
	(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:
	•	2014 are attributable to our West Texas Asset as we drilled in areas not previously explored;
	•	2013 are attributable to our Barnett Shale Asset; and
	•	2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed).
	Canadian extensions and discoveries for 2013 and 2012 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 49,712 MMcfe, 419,972 MMcfe and (590,064) MMcfe in 2014, 2013 and 2012, respectively, and changes in non-economic factors of (177,246) MMcfe, (151,615) MMcfe and (629,407) MMcfe in 2014, 2013 and 2012, respectively, including:
	•	In 2014, we removed proved reserves of (143) Bcfe that we were unable to develop due to constrained liquidity
	•	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: (34) Bcfe, (74) Bcfe and (291) Bcfe in 2014, 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]
		U.S.				Canada				Consolidated
		(in thousands)
	2014
	Proved properties	$	4,650,428			$	1,170,739			$	5,821,167
	Unevaluated properties	18,803				—				18,803
	Accumulated DD&A	(4,296,953		)		(928,349		)		(5,225,302		)
	Net capitalized costs	$	372,278			$	242,390			$	614,668
	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
Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities Disclosure [Table Text Block]
		U.S.				Canada				Consolidated
		(in thousands)
	2014
	Proved acreage	$	—			$	—			$	—
	Unproved acreage	21,722				5,519				27,241
	Development costs	78,894				22,065				100,959
	Exploration costs	63				—				63
	Total	$	100,679			$	27,584			$	128,263
	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
Results of Operations for Oil and Gas Producing Activities Disclosure [Table Text Block]
		U.S.				Canada				Consolidated
		(in thousands)
	2014
	Natural gas, NGL and oil revenue	$	292,388			$	132,766			$	425,154
	Operating expense	146,383				84,219				230,602
	Depletion expense	28,567				11,778				40,345
		117,438				36,769				154,207
	Income tax expense	41,103				9,266				50,369
	Results from producing activities	$	76,335			$	27,503			$	103,838
	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	)
Schedule of Prices used for Standardized Measure [Table Text Block]
		At December 31,
		2014				2013				2012
	Natural gas – Henry Hub, per MMBtu	$	4.35			$	3.67			$	2.76
	Natural gas – AECO, per MMBtu	4.22				2.9				2.35
	Oil – WTI Cushing, per Bbl	94.99				97.18				94.71
Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure [Table Text Block]
		U.S.				Canada				Total
						(in thousands)
	31-Dec-14
	Future revenue	$	3,476,515			$	1,053,509			$	4,530,024
	Future production costs	(1,785,208		)		(483,380		)		(2,268,588		)
	Future development costs	(71,143		)		(65,703		)		(136,846		)
	Future income taxes	(113,119		)		(11,017		)		(124,136		)
	Future net cash flows	1,507,045				493,409				2,000,454
	10% discount	(817,744		)		(194,640		)		(1,012,384		)
	Standardized measure of discounted future cash flows relating to proved reserves	$	689,301			$	298,769			$	988,070
	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
Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows [Table Text Block]	The primary changes in the Standardized Measure for 2014, 2013 and 2012 were as follows:
		Years Ended December 31,
		2014				2013				2012
						(in thousands)
	Sales of oil and natural gas net of production costs	$	(164,436	)		$	(147,402	)		$	(149,326	)
	Net changes in economic factors	304,602				326,698				(1,362,793		)
	Extensions and discoveries	1,455				43,328				27,003
	Development costs incurred	60,169				2,302				172,563
	Changes in estimated future development costs	91,635				20,766				620,127
	Purchase and sale of reserves, net	(24		)		(237,409		)		(20,529		)
	Revision of estimates	(103,478		)		121,916				(1,219,609		)
	Accretion of discount	75,925				50,821				196,315
	Net change in income taxes	(73,637		)		(86,667		)		560,485
	Change in timing and other differences	(27,189		)		13,575				156,031
	Net increase (decrease)	$	165,022			$	107,928			$	(1,019,733	)

Significant_Accounting_Policie1

Significant Accounting Policies (Policy)	12 Months Ended
	Dec. 31, 2014
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
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 2014, two purchasers individually accounted for 17% and 13% of cash collected for our production revenue. During 2013, one purchaser individually accounted for 18% of cash collected for our production revenue. During 2012, two purchasers accounted for 21% and 15% 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.
	To the extent we enter into derivatives, these positions are 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 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.
Property, Plant and Equipment	Property, Plant, and Equipment
	We follow the full cost method in accounting for our oil and natural gas properties. Under the full cost method, all costs associated with the acquisition, exploration and development of oil and natural 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, which costs are assessed annually for impairment and inclusion as depletable costs in the respective cost center.
	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 natural 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 oil and natural gas 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 7 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, included in Other Current Assets, were comprised of $7.6 million and $15.8 million of materials and parts and $0.7 million and $2.5 million of NGLs as of December 31, 2014 and 2013, respectively. Inventories are primarily comprised of materials and parts including oil and natural 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 of $7.0 million and $3.0 million for 2014 and 2013, respectively, 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, 2014 and 2013, 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 within debt. 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 12 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. Losses from foreign currency transactions of $3.7 million and $2.4 million in 2014 and 2013, respectively, 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.
	We consolidate the financial position of Fortune Creek and the results of operations in our consolidated financial statements. Note 14 contains additional discussion regarding Fortune Creek.
Earnings per Share	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 16 includes the calculation of earnings per share.
New Accounting Pronouncements, Policy [Policy Text Block]	Recently Issued Accounting Standards
	In February 2015, the FASB issued accounting guidance, “Consolidation (Topic 810): Amendments to the Consolidation Analysis,” requiring reporting entities to evaluate whether they should consolidate certain legal entities. The standard is effective for periods beginning after December 15, 2015 with early adoption permitted. We are currently evaluating the new guidance and have not determined the impact this standard may have on our financial statements.
	In May 2014, the FASB issued accounting guidance, “Revenue from Contracts with Customers,” requiring an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The updated standard will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective and permits the use of either the retrospective or cumulative effect transition method. Early adoption is not permitted. The updated standard becomes effective for us in the first quarter of 2017. We have not yet selected a transition method and we are currently evaluating the effect, if any, that the updated standard will have on our consolidated financial statements and related disclosures.
	No other pronouncements materially affecting our financial statements have been issued since the filing of our 2013 Annual Report on Form 10-K.

Derivatives_And_Fair_Value_Mea1

Derivatives And Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
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,
		2014			2013			2014			2013
		(in thousands)						(in thousands)
	Level 2 inputs	$	104,608		$	107,395		$	—		$	3,448
	Level 3 inputs	44,959			23,485			—			—
	Total	$	149,567		$	130,880		$	—		$	3,448
Changes In Level 3 Fair Values
		As of December 31,
		2014			2013
		(in thousands)
	Balance at beginning of period	$	23,485		$	(4,931	)
	Total gains (losses) for the period:
	Unrealized gain on derivatives	31,824			40,398
	Transfers out of Level 3	(3,559		)	—
	Settlements in net derivative losses	(6,791		)	(11,982		)
	Balance at end of period	$	44,959		$	23,485
	Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	$	32,074		$	41,909
Price Collars And Swaps For Anticipated Natural Gas Production
	Production		Daily Production
	Year		Volume
			Natural Gas
			MMcfd
	2015		150
	2016-2021		30
Net Deferred Hedge Gain in AOCI to be Released into Earnings in a Future Period [Table Text Block]
		(in thousands)
	2015	$	33,191
	2016	13,476
	2017	12,531
	2018	11,664
	2019 and thereafter	29,779
		$	100,641
Reduction Of Interest Expense Over The Life Of The Debt Instruments
		(in thousands)
	2015	$	2,194
	2016	569
		$	2,763
Estimated Fair Value Of Derivative Instruments
		Asset Derivatives							Liability Derivatives
		As of December 31,							As of December 31,
		2014			2013				2014			2013
		(in thousands)							(in thousands)
	Derivatives not designated as hedges:
	Commodity contracts reported in:
	Current derivative assets	$	120,176		$	60,063			$	—		$	2,540
	Noncurrent derivative assets	81,187			105,315				51,796			31,958
	Current derivative liabilities	—			—				—			3,125
	Noncurrent derivative liabilities	—			—				—			323
	Total derivatives not designated as hedges	$	201,363		$	165,378			$	51,796		$	37,946
Held-to-maturity Securities
		31-Dec-13
		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, 2014
Accounts Receivable, Net [Abstract]
Schedule Of Accounts Receivable
		As of December 31,
		2014			2013
		(in thousands)
	Accrued production revenue	$	32,130		$	34,785
	Joint interest billings	22,621			15,630
	Income taxes	7,574			7,931
	Canadian value added taxes	173			60
	Other	2,937			328
	Allowance for doubtful accounts	(277		)	(89		)
		$	65,158		$	58,645

Other_Current_Assets_Tables

Other Current Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Other Current Assets [Abstract]
Other Current Assets
		As of December 31,
		2014		2013
		(in thousands)
	Inventories	$	8,269	$	18,334
	Deposits	1,284		1,044
	Other prepaid expense	4,861		2,968
		$	14,414	$	22,346

Property_Plant_And_Equipment_T

Property, Plant And Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Schedule Of Property, Plant And Equipment
		As of December 31,
		2014				2013
		(in thousands)
	Oil and natural gas properties
	Subject to depletion	$	5,821,167			$	5,687,557
	Unevaluated costs	18,803				221,605
	Accumulated depletion	(5,225,302		)		(5,268,719		)
	Net oil and natural gas properties	614,668				640,443
	Other property and equipment
	Pipelines and processing facilities	316,013				347,093
	General properties	66,455				72,125
	Accumulated depreciation	(268,356		)		(198,856		)
	Net other property and equipment	114,112				220,362
	Property, plant and equipment, net of accumulated depletion and depreciation	$	728,780			$	860,805
Schedule Of Charges For Impairment
				Pre-tax Charges for Impairment
		Segment		2014				2013				2012
				(in thousands)
	U.S.
	Oil and natural gas properties	Exploration and production		$	—			$	—			$	2,152,128
	Other property and equipment	Midstream		135				54				7,328
	Other property and equipment	Exploration and production		2,450				1,809				537
	Canada
	Oil and natural gas properties	Exploration and production		—				—				465,935
	Other property and equipment	Midstream		58,360				—				—
	Other property and equipment	Exploration and production		11,043				—				—
				$	71,988			$	1,863			$	2,625,928
Schedule Of Unevaluated Natural Gas And Oil Properties Not Subject To Depletion
		December 31, 2014 Costs Incurred During																December 31, 2013 Costs Incurred During
		2014				2013				2012				Prior		Total		2013		2012		2011		Prior		Total
		(in thousands)																(in thousands)
	U.S.
	Acquisition costs	$	5,637			$	—			$	1,574			$	9,029	$	16,240	$	—	$	3,013	$	13,484	$	—	$	16,497
	Exploration costs	—				—				—				—		—		14		364		—		—		378
	Capitalized interest	395				961				1,207				—		2,563		1,093		1,374		—		—		2,467
	Total U.S.	$	6,032			$	961			$	2,781			$	9,029	$	18,803	$	1,107	$	4,751	$	13,484	$	—	$	19,342
	Canada
	Acquisition costs	$	—			$	—			$	—			$	—	$	—	$	—	$	2,956	$	1,300	$	68,586	$	72,842
	Exploration costs	—				—				—				—		—		7,044		31,746		41,092		30,413		110,295
	Capitalized interest	—				—				—				—		—		3,947		2,724		3,522		8,933		19,126
	Total Canada	$	—			$	—			$	—			$	—	$	—	$	10,991	$	37,426	$	45,914	$	107,932	$	202,263
	Total	$	6,032			$	961			$	2,781			$	9,029	$	18,803	$	12,098	$	42,177	$	59,398	$	107,932	$	221,605
Schedule Of Unevaluated Property Costs
		As of December 31,
		2014				2013
		(in thousands)
	West Texas	$	18,803			$	19,343
	Horn River Basin	—				202,262
	Total	$	18,803			$	221,605

Other_Assets_Tables

Other Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Other Assets, Noncurrent Disclosure [Abstract]
Schedule Of Other Assets
		As of December 31,
		2014			2013
		(in thousands)
	Deferred financing costs	$	62,319		$	84,951
	Less accumulated amortization	(33,472		)	(50,171		)
	Net deferred financing costs	28,847			34,780
	Governmental and notes receivable	3,888			6,464
	Other	119			360
		$	32,854		$	41,604

Accrued_Liabilities_Tables

Accrued Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities [Abstract]
Schedule Of Accrued Liabilities
		As of December 31,
		2014		2013
		(in thousands)
	Interest payable	$	36,288	$	38,260
	Accrued operating expense	21,833		37,747
	Prepayments from partners	—		425
	Revenue payable	19,121		22,589
	Accrued state income and franchise taxes	55		1,080
	Accrued production and property taxes	677		870
	Environmental liabilities	18		36
	Accrued product purchases	310		270
	Current asset retirement obligations	967		433
	Other	1,877		1,140
		$	81,146	$	102,850

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Instrument [Line Items]
Schedule of Debt
			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		2019		2021		Senior
			Agreements						Senior Notes		Senior Notes		Subordinated Notes
	Principal amount (1)(2)		$325 million		$625 million		$200 million		$298 million		$325 million		$350 million
	Scheduled maturity date (3)		September 6, 2016		June 21, 2019		June 21, 2019		August 15, 2019		July 1, 2021		April 1, 2016
	Springing maturity date (3)		2-Oct-15		1-Jan-16		1-Jan-16		N/A		N/A		N/A
	Interest rate on outstanding borrowings at December 31, 2014 (4)		4.10%		7.00%		7.00%		9.13%		11.00%		7.12%
	Base interest rate options (5)(6)		LIBOR, ABR, CDOR		LIBOR floor of 1.25%; ABR floor of 2.25%		LIBOR floor of 1.25%		N/A		N/A		N/A
	Financial covenants (7)(9)		- Minimum current ratio of 1.0		N/A		N/A		N/A		N/A		N/A
			- Minimum EBITDAX or EBITDA to cash interest expense
			- Maximum senior secured debt leverage ratio of 2.0
	Significant restrictive covenants (8)(9)		- Incurrence of debt		- Incurrence of debt		- Incurrence of debt		- 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 (9)		Any time		Any time, subject to re-pricing event		Any time, subject to re-pricing event		August 15,		July 1,		Any time
					June 21, 2015: 101		June 21, 2015: 101		2014: 104.563		2019: 102.000
									2015: 103.042		2020: par
									2016: 101.521
									2017: par
	Make-whole redemption (9)		N/A		N/A		N/A		N/A		Callable prior to		N/A
											July 1, 2019 at
											make-whole call price
											of Treasury +50 bps
	Change of control (9)		Event of default		Put at 101% of		Put at 101% of		Put at 101% of		Put at 101% of		Put at 101% of
					principal plus accrued		principal plus accrued		principal plus accrued		principal plus accrued		principal plus accrued
					interest		interest		interest		interest		interest
	Equity clawback (9)		N/A		N/A		N/A		N/A		Redeemable until		N/A
											July 1, 2016 at
											111.00%, plus accrued
											interest for up to 35%
	Estimated fair value (10)		$274.5 million		$465.6 million		$149.0 million		$74.8 million		$87.9 million		$26.5 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 natural 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 natural 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, 2014.
	-3	The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 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 Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of December 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.
	-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%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate of ABR plus the applicable margin.
	-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%. Beginning on March 17, 2015, as part of the Forbearance Agreement, we agreed to pay interest monthly at a specified rate for Canadian dollar denominated borrowings of Canadian prime plus the default rate plus the applicable margin and for U.S. dollar denominated borrowings, U.S. prime plus the default rate plus the applicable margin.
	-7	As of December 31, 2014, the minimum EBITDAX covenant for the Combined Credit Agreements is as follows:
		Minimum EBITDAX Covenant
		(in millions)
	Three months ending December 31, 2014	$	30
	Six months ending March 31, 2015	59
	Nine months ending June 30, 2015	87.25
	Twelve months ending September 30, 2015	120.5
	Twelve months ending December 31, 2015	122
	The minimum required interest coverage ratio for the Combined Credit Agreements for first quarter of 2016 and second quarter of 2016 is 1.50 and 2.00, respectively.
	(8)	Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.
	(9)	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.
	(10)	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 and a first priority lien to have a fair value equal to their carrying value (“Level 1” input).
Schedule of Maturities of Long-term Debt
		2015				2016				2017				2018		2019		Thereafter
		(in thousands)
	Combined Credit Agreements	$	—			$	274,514			$	—			$	—	$	—	$	—
	Second Lien Term Loan	—				—				—				—		625,000		—
	Second Lien Notes due 2019	—				—				—				—		200,000		—
	Senior Notes due 2019	—				—				—				—		298,000		—
	Senior Notes due 2021	—				—				—				—		—		325,000
	Senior Subordinated Notes due 2016	—				350,000				—				—		—		—
	Total Indebtedness	$	—			$	624,514			$	—			$	—	$	1,123,000	$	325,000
Schedule of Long-term Debt Instruments [Table Text Block]
		As of December 31,
		2014				2013
		(in thousands)
	Combined Credit Agreements	$	274,514			$	211,200
	Second Lien Term Loan, net of unamortized discount of $14,758 and $17,428	610,242				607,572
	Second Lien Notes due 2019, net of unamortized discount of $4,723 and $5,577	195,277				194,423
	Senior Notes due 2015, net of unamortized discount of $0 and $2,149	—				10,472
	Senior Notes due 2016, net of unamortized discount of $0 and $10,825	—				8,044
	Senior Notes due 2019, net of unamortized discount of $4,081 and $5,378	293,919				293,243
	Senior Notes due 2021, net of unamortized discount of $14,410 and $15,810	310,590				309,190
	Senior Subordinated Notes due 2016	350,000				350,000
	Total debt	2,034,542				1,984,144
	Unamortized deferred gain—terminated interest rate swaps	2,763				4,802
	Current portion of long-term debt	(2,037,305		)		—
	Long-term debt	$	—			$	1,988,946
QRI & Restricted Subsidiaries Indenture Financials (Balance Sheet)
		December 31,
		2014				2013
		(in thousands)
	ASSETS
	Current assets	$	421,533			$	393,713
	Property and equipment	715,931				779,173
	Investment in subsidiaries (equity method)	(82,360		)		(33,840		)
	Other assets	62,245				114,961
	Total assets	$	1,117,349			$	1,254,007
	LIABILITIES AND EQUITY
	Current liabilities	2,137,532				134,010
	Long-term liabilities	117,688				2,113,221
	Stockholders’ equity	(1,137,871		)		(993,224		)
	Total liabilities and equity	$	1,117,349			$	1,254,007
QRI & Restricted Subsidiaries Indenture Financials (Income Statement)
		For the Year Ended
		2014				2013				2012
		(in thousands)
	Revenue	$	569,428			$	561,562			$	709,038
	Operating expenses	434,998				448,802				3,222,595
	Tokyo Gas Transaction gain	—				339,328				—
	Crestwood earn-out	—				—				41,097
	Equity in net earnings of subsidiaries	(64,056		)		(6,682		)		(12,747		)
	Operating income (loss)	70,374				445,406				(2,485,207		)
	Interest expense and other	(169,874		)		(269,238		)		(162,991		)
	Income tax (expense) benefit	(3,600		)		(14,550		)		295,592
	Net income (loss)	$	(103,100	)		$	161,618			$	(2,352,606	)
	Other comprehensive loss	(38,028		)		(51,612		)		(53,365		)
	Comprehensive income (loss)	$	(141,128	)		$	110,006			$	(2,405,971	)
QRI & Restricted Subsidiaries Indenture Financials (Cash Flow)
		For the Year Ended
		2014				2013				2012
		(in thousands)
	Net cash flow provided by (used in) operating activities	$	(13,614	)		$	(62,131	)		$	213,280
	Capital expenditures	(133,481		)		(100,783		)		(474,748		)
	Investment in subsidiary	(26,395		)		—				—
	Proceeds from Southwestern Transaction	95,587				—				—
	Proceeds from Tokyo Gas Transaction	—				463,999				—
	Proceeds from Synergy Transaction	—				42,297				—
	Proceeds from Crestwood earn-out	—				—				41,097
	Proceeds from sale of properties and equipment	3,222				7,171				72,725
	Purchases of marketable securities	(55,890		)		(213,738		)		—
	Maturities and sales of marketable securities	222,025				47,603				—
	Net cash flow provided by (used in) investing activities	105,068				246,549				(360,926		)
	Issuance of debt	243,184				1,237,352				467,959
	Repayments of debt	(193,689		)		(1,308,382		)		(310,430		)
	Debt issuance costs paid	(1,705		)		(26,296		)		(3,022		)
	Proceeds from exercise of stock options	—				—				11
	Purchase of treasury stock	(2,388		)		(1,927		)		(3,144		)
	Net cash flow provided by (used in) financing activities	45,402				(99,253		)		151,374
	Effect of exchange rates on cash	(3,046		)		(1,755		)		527
	Net increase in cash and equivalents	133,810				83,410				4,255
	Cash and equivalents at beginning of period	88,028				4,618				363
	Cash and equivalents at end of period	$	221,838			$	88,028			$	4,618

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation [Abstract]
Estimated Asset Retirement Obligation Activity
		As of December 31,
		2014			2013
		(in thousands)
	Beginning asset retirement obligations	$	106,689		$	116,526
	Additional liability incurred	269			3,922
	Change in estimates	(229		)	7,582
	Accretion expense	5,618			5,109
	Asset retirement costs incurred	(388		)	(1,560		)
	Settlement of liability in excess of obligation recorded	146			742
	Disposition	(1,778		)	(21,935		)
	Currency translation adjustment	(5,311		)	(3,697		)
	Ending asset retirement obligations	105,016			106,689
	Less current portion	(967		)	(433		)
	Long-term asset retirement obligation	$	104,049		$	106,256

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Components of Deferred Tax Assets and Liabilities [Abstract]
Significant Components Of Deferred Tax Assets And Liabilities
		As of December 31,
		2014				2013
		(in thousands)
	Deferred tax assets:
	Property, plant and equipment	$	148,360			$	209,134
	Net operating loss carry-forwards	289,261				183,982
	Investment in Fortune Creek	3,763				3,763
	AMT tax credit	40,309				47,883
	Settlements of interest rate swaps	967				1,681
	Deferred compensation expense	11,087				11,711
	State	2,048				3,680
	Other	421				791
	Deferred tax assets	496,216				462,625
	Deferred tax liabilities:
	Net derivative gains	(61,638		)		(44,039		)
	Other	(470		)		(991		)
	Deferred tax liabilities	(62,108		)		(45,030		)
	Net deferred tax asset (liability)	434,108				417,595
	Valuation allowance	(434,108		)		(417,595		)
	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
		2014				2013				2012
						(in thousands)
	U.S.	$	(41,865	)		$	184,034			$	(2,142,730	)
	Canada	(57,635		)		(7,866		)		(505,446		)
	Total	$	(99,500	)		$	176,168			$	(2,648,176	)
Components Of Income Tax Expense
		2014				2013				2012
						(in thousands)
	Current state income tax expense (benefit)	$	(144	)		$	900			$	1,752
	Current U.S. federal income tax benefit	(7,574		)		(7,931		)		—
	Current Canadian income tax expense	559				—				—
	Total current income tax expense (benefit)	(7,159		)		(7,031		)		1,752
	Deferred U.S. federal income tax expense (benefit)	(11,238		)		205,820				(763,639		)
	U.S. federal valuation allowance expense	21,011				(186,713		)		533,974
	Deferred state income tax expense (benefit)	1,632				(3,680		)		—
	State valuation allowance expense	(1,632		)		3,680				—
	Deferred Canadian income tax expense (benefit)	3,620				827				(128,982		)
	Canadian valuation allowance expense	(2,634		)		1,647				61,325
	Total deferred income tax expense (benefit)	10,759				21,581				(297,322		)
	Total income tax expense (benefit)	$	3,600			$	14,550			$	(295,570	)
Statutory Federal Income Tax Rate
		2014			2013			2012
	U.S. federal statutory tax rate	35	%		35	%		35	%
	Permanent differences	(27.05	)%		4.8	%		(0.06	)%
	State income taxes net of federal deduction	0.09	%		0.31	%		(0.04	)%
	Canadian income taxes	1.4	%		(0.26	)%		(1.93	)%
	Other	(0.30	)%		(0.15	)%		0.67	%
	Derivatives deferred in OCI	(11.07	)%		12.43	%		—	%
	AMT NOL refund	7.61	%		—	%		—	%
	Valuation allowance	(9.30	)%		(43.87	)%		(22.48	)%
	Effective income tax rate	(3.62	)%		8.26	%		11.16	%

Commitments_And_Contingencies_

Commitments And Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Loss Contingency [Abstract]
Summary Of Contractual Obligations
		GPT		Drilling Rig		Operating		Purchase
		Contracts (1)		Contracts (2)		Leases (3)		Obligations (4)
		(in thousands)
	2015	$	72,995	$	6,577	$	4,181	$	220
	2016	69,566		—		4,275		—
	2017	66,492		—		4,098		—
	2018	60,453		—		3,961		—
	2019	44,241		—		4,001		—
	Thereafter	95,250		—		8,849		—
	Total	$	408,997	$	6,577	$	29,365	$	220
	(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 unused firm capacity rate. Our gathering and transportation contracts with CMLP have no minimum volume requirement and, therefore, are not reported in the above amounts. As described below, this amount includes an amount we expect the service provider will claim to be entitled to with respect to QRCI's gathering and processing contract as of December 31, 2014. As further described below, the contract was terminated in March 2015 and we expect that we and the third party will disagree regarding the remaining amounts payable under the contract.
	(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 ranging from $23,000 to $24,300 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 $3.5 million in 2014, $3.6 million in 2013 and $4.2 million in 2012. Minimum payments have not been reduced by minimum sublease rentals of $1.6 million due in the future under noncancelable subleases.
	(4)	At December 31, 2014, we were under contract to purchase goods and services.

Quicksilver_Stockholders_Equit1

Quicksilver Stockholders' Equity (Tables)	12 Months Ended
	Dec. 31, 2014
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, 2012	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
	Stock options exercised	—			—
	Restricted stock activity	3,808,115			745,732
	Balance at December 31, 2014	187,802,994			7,444,372
Assumptions For The Black-Scholes Option Pricing Model For Stock Options Issued
		2013		2012
	Weighted average grant date fair value	$1.05		$4.21
	Weighted average risk-free interest rate	1.31%		1.14%
	Expected life	4.9 years		6.0 years
	Weighted average volatility	68.97%		68.20%
	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, 2014	6,771,578			$	7.82
	Forfeited	(60,939	)		3.04
	Expired	(119,866	)		9.8
	Outstanding at December 31, 2014	6,590,773			$	7.83	5.1		$	—
	Exercisable at December 31, 2014	5,224,531			$	9.18	4.3		$	—
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, 2014	5,668,090			$	3.9	1,572,341			$	3.69
	Granted	6,070,563			2.19		—			—
	Vested	(2,559,959	)		4.86		(636,146	)		4.27
	Forfeited	(1,122,429	)		2.26		(72,220	)		3.28
	Outstanding at December 31, 2014	8,056,265			$	2.54	863,975			$	3.33

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Reconciliation Of Components Used To Compute Basic And Diluted Earnings (Loss) Per Common Share
		Years Ended December 31,
		2014			2013			2012
		(in thousands, except per share data)
	Net income (loss) attributable to Quicksilver	$	(103,100	)	$	161,618		$	(2,352,606	)
	Basic income allocable to participating securities (1)	—			(4,252		)	—
	Income (loss) available to shareholders	$	(103,100	)	$	157,366		$	(2,352,606	)
	Weighted average common shares – basic	173,822			171,518			170,106
	Effect of dilutive securities (2)
	Share-based compensation awards	—			141			—
	Weighted average common shares — diluted	173,822			171,659			170,106
	Earnings (loss) per common share — basic	$	(0.59	)	$	0.92		$	(13.83	)
	Earnings (loss) per common share — diluted	$	(0.59	)	$	0.92		$	(13.83	)
	(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 2014, 6.6 million shares associated with our stock options and 1.0 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. 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.

Condensed_Consolidating_Financ1

Condensed Consolidating Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
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
	Cowtown Pipeline Management, Inc.		Cowtown Drilling Inc. (1)		1622834 Alberta Inc.
	Cowtown Pipeline L.P.		Quicksilver Resources Partners Operating Ltd. (2)		Makarios Midstream Inc.
	Cowtown Gas Processing L.P.		0942065 B.C. Ltd. (2)		Makarios Resources International Inc.
	Barnett Shale Operating LLC		0942069 B.C Ltd. (2)		Quicksilver Production Partners GP LLC
	QPP Parent LLC (2)				Quicksilver Production Partners LP
	QPP Holdings LLC (2)
	Silver Stream Pipeline Company LLC (2)
	-1	This entity was inactive for the three-year period ended December 31, 2014.
	(2)	These entities were created in 2012.
Condensed Consolidating Balance Sheets	Condensed Consolidating Balance Sheets
		31-Dec-14
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	ASSETS
	Current assets	$	774,287			$	13,909		$	68,513		$	82		$	1,742		$	(435,256	)	$	423,277
	Property and equipment	420,744				14,357			280,830			—			12,849			—			728,780
	Investment in subsidiaries (equity method)	(293,312		)		—			(82,360		)	(82,379		)	—			458,051			—
	Other assets	43,533				—			18,712			—			—			—			62,245
	Total assets	$	945,252			$	28,266		$	285,695		$	(82,297	)	$	14,591		$	22,795		$	1,214,302
	LIABILITIES AND EQUITY
	Current liabilities	$	2,038,575			$	13,837		$	520,296		$	63		$	3,522		$	(435,256	)	$	2,141,037
	Long-term liabilities	44,548				15,131			58,009			—			1,492			91,956			211,136
	Stockholders’ equity	(1,137,871		)		(702		)	(292,610		)	(82,360		)	9,577			366,095			(1,137,871		)
	Total liabilities and equity	$	945,252			$	28,266		$	285,695		$	(82,297	)	$	14,591		$	22,795		$	1,214,302
		31-Dec-13
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	ASSETS
	Current assets	$	349,586			$	10,735		$	53,034		$	909		$	1,110		$	(21,414	)	$	393,960
	Property and equipment	455,822				15,486			307,865			—			81,632			—			860,805
	Investment in subsidiaries (equity method)	(217,852		)		—			(33,840		)	(33,840		)	—			285,532			—
	Other assets	472,792				—			32,892			—			—			(390,723		)	114,961
	Total assets	$	1,060,348			$	26,221		$	359,951		$	(32,931	)	$	82,742		$	(126,605	)	$	1,369,726
	LIABILITIES AND EQUITY
	Current liabilities	$	124,275			$	12,210		$	17,167		$	888		$	1,671		$	(21,414	)	$	134,797
	Long-term liabilities	1,942,043				19,242			542,659			—			1,546			(264,591		)	2,240,899
	Stockholders’ equity	(1,005,970		)		(5,231		)	(199,875		)	(33,819		)	79,525			159,400			(1,005,970		)
	Total liabilities and equity	$	1,060,348			$	26,221		$	359,951		$	(32,931	)	$	82,742		$	(126,605	)	$	1,369,726
Condensed Consolidating Statements Of Income	Condensed Consolidating Statements of Income
		For the Year Ended December 31, 2014
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	Revenue	$	410,455			$	5,730		$	153,243		$	—		$	17,585		$	(17,585	)	$	569,428
	Operating expenses	299,499				1,286			134,213			—			66,581			(17,585		)	483,994
	Equity in net earnings of subsidiaries	(55,678		)		—			(64,056		)	(48,989		)	—			168,723			—
	Operating income (loss)	55,278				4,444			(45,026		)	(48,989		)	(48,996		)	168,723			85,434
	Fortune Creek accretion	—				—			—			—			—			(15,067		)	(15,067		)
	Interest expense and other	(157,350		)		86			(12,610		)	—			7			—			(169,867		)
	Income tax (expense) benefit	(2,614		)		(1,586		)	(986		)	—			—			1,586			(3,600		)
	Net income (loss)	$	(104,686	)		$	2,944		$	(58,622	)	$	(48,989	)	$	(48,989	)	$	155,242		$	(103,100	)
	Other comprehensive income (loss)	(31,476		)		—			(6,552		)	—			—			—			(38,028		)
	Equity in OCI of subsidiaries	(6,552		)		—			—			—			—			6,552			—
	Comprehensive income (loss)	$	(142,714	)		$	2,944		$	(65,174	)	$	(48,989	)	$	(48,989	)	$	161,794		$	(141,128	)
		For the Year Ended December 31, 2013
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Inc.
																					Consolidated
		(in thousands)
	Revenue	$	416,516			$	788		$	144,258		$	—		$	22,364		$	(22,364	)	$	561,562
	Operating expenses	329,975				346			118,481			—			9,808			(22,364		)	436,246
	Tokyo Gas Transaction gain	339,328				—			—			—			—			—			339,328
	Equity in net earnings of subsidiaries	(9,896		)		—			(6,682		)	12,563			—			4,015			—
	Operating income (loss)	415,973				442			19,095			12,563			12,556			4,015			464,644
	Fortune Creek accretion	—				—			—			—			—			(19,245		)	(19,245		)
	Interest expense and other	(242,279		)		—			(26,959		)	—			7			—			(269,231		)
	Income tax expense	(12,076		)		—			(2,474		)	—			—			—			(14,550		)
	Net income (loss)	$	161,618			$	442		$	(10,338	)	$	12,563		$	12,563		$	(15,230	)	$	161,618
	Other comprehensive loss	(40,166		)		—			(11,446		)	—			—			—			(51,612		)
	Equity in OCI of subsidiaries	(11,446		)		—			—			—			—			11,446			—
	Comprehensive income (loss)	$	110,006			$	442		$	(21,784	)	$	12,563		$	12,563		$	(3,784	)	$	110,006
		For the Year Ended December 31, 2012
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources Inc.
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
		(in thousands)
	Revenue	$	611,477			$	4,574		$	95,887		$	—		$	14,639		$	(17,539	)	$	709,038
	Operating expenses	2,643,690				4,109			577,696			—			7,940			(17,539		)	3,215,896
	Crestwood earn-out	41,097				—			—			—			—			—			41,097
	Equity in net earnings of subsidiaries	(437,510		)		—			(12,747		)	6,726			—			443,531			—
	Operating income (loss)	(2,428,626		)		465			(494,556		)	6,726			6,699			443,531			(2,465,761		)
	Fortune Creek accretion	—				—			—			—			—			(19,472		)	(19,472		)
	Interest expense and other	(152,077		)		—			(10,914		)	21			27			—			(162,943		)
	Income tax (expense) benefit	228,097				(163		)	67,658			—			—			(22		)	295,570
	Net income (loss)	$	(2,352,606	)		$	302		$	(437,812	)	$	6,747		$	6,726		$	424,037		$	(2,352,606	)
	Other comprehensive income (loss)	(57,273		)		—			3,908			—			—			—			(53,365		)
	Equity in OCI of subsidiaries	3,908				—			—			—			—			(3,908		)	—
	Comprehensive income (loss)	$	(2,405,971	)		$	302		$	(433,904	)	$	6,747		$	6,726		$	420,129		$	(2,405,971	)
Condensed Consolidating Statements Of Cash Flows	Condensed Consolidating Statements of Cash Flow
		For the Year Ended December 31, 2014
		Quicksilver				Restricted			Restricted			Unrestricted			Fortune			Consolidating			Quicksilver
		Resources				Guarantor			Non-Guarantor			Non-Guarantor			Creek			Eliminations			Resources Inc.
		Inc.				Subsidiaries			Subsidiaries			Subsidiaries									Consolidated
		(in thousands)
	Net cash flow provided by (used in) operating activities	$	(43,824	)		$	(1,349	)	$	31,559		$	(2	)	$	5,987		$	—		$	(7,629	)
	Capital expenditures	(102,898		)		(60		)	(30,523		)	—			—			—			(133,481		)
	Investment in subsidiary	881				—			(26,395		)	(26,395		)	—			51,909			—
	Proceeds from Southwestern Transaction	95,587				—			—			—			—			—			95,587
	Proceeds from sale of properties and equipment	2,549				—			673			—			—			—			3,222
	Purchases of marketable securities	(55,890		)		—			—			—			—			—			(55,890		)
	Maturities and sales of marketable securities	222,025				—			—			—			—			—			222,025
	Net cash flow provided by (used in) investing activities	162,254				(60		)	(56,245		)	(26,395		)	—			51,909			131,463
	Issuance of debt	174,000				—			69,184			—			—			—			243,184
	Repayments of debt	(138,651		)		—			(55,038		)	—			—			—			(193,689		)
	Debt issuance costs	(1,069		)		—			(636		)	—			—			—			(1,705		)
	Intercompany note	(22,559		)		—			22,559			—			—			—			—
	Intercompany financing	—				1,409			(2,290		)	—			—			881			—
	Contribution received	—				—			—			26,395			26,395			(52,790		)	—
	Distribution of Fortune Creek Partnership funds	—				—			—			—			(39,993		)	—			(39,993		)
	Purchase of treasury stock	(2,388		)		—			—			—			—			—			(2,388		)
	Net cash flow provided by (used in) financing activities	9,333				1,409			33,779			26,395			(13,598		)	(51,909		)	5,409
	Effect of exchange rates on cash	—				—			(3,046		)	—			8,229			—			5,183
	Net increase in cash and equivalents	127,763				—			6,047			(2		)	618			—			134,426
	Cash and equivalents at beginning of period	83,893				—			4,135			22			1,053			—			89,103
	Cash and equivalents at end of period	$	211,656			$	—		$	10,182		$	20		$	1,671		$	—		$	223,529
		For the Year Ended December 31, 2013
		Quicksilver				Restricted			Restricted			Unrestricted Non-Guarantor Subsidiaries			Fortune Creek			Quicksilver
		Resources				Guarantor			Non-Guarantor									Resources
		Inc.				Subsidiaries			Subsidiaries									Inc.
																		Consolidated
		(in thousands)
	Net cash flow provided by (used in) operating activities	$	(82,722	)		$	—		$	20,591		$	22		$	10,409		$	(51,700	)
	Capital expenditures	(67,263		)		—			(33,520		)	—			(505		)	(101,288		)
	Proceeds from Tokyo Gas Transaction	463,999				—			—			—			—			463,999
	Proceeds from Synergy Transaction	42,297				—			—			—			—			42,297
	Proceeds from sale of properties and equipment	7,128				—			43			—			—			7,171
	Purchases of marketable securities	(213,738		)		—			—			—			—			(213,738		)
	Maturities and sales of marketable securities	47,603				—			—			—			—			47,603
	Net cash flow provided by (used in) investing activities	280,026				—			(33,477		)	—			(505		)	246,044
	Issuance of debt	1,215,266				—			22,086			—			—			1,237,352
	Repayments of debt	(1,157,969		)		—			(150,413		)	—			—			(1,308,382		)
	Debt issuance costs	(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		)
	Net cash flow provided by (used in) financing activities	(118,029		)		—			18,776			—			(14,965		)	(114,218		)
	Effect of exchange rates on cash	—				—			(1,755		)	—			5,781			4,026
	Net increase in cash and equivalents	79,275				—			4,135			22			720			84,152
	Cash and equivalents at beginning of period	4,618				—			—			—			333			4,951
	Cash and equivalents at end of period	$	83,893			$	—		$	4,135		$	22		$	1,053		$	89,103
		For the Year Ended December 31, 2012
		Quicksilver				Restricted			Restricted			Unrestricted Non-Guarantor Subsidiaries			Fortune			Quicksilver
		Resources				Guarantor			Non-Guarantor						Creek			Resources
		Inc.				Subsidiaries			Subsidiaries									Inc.
																		Consolidated
		(in thousands)
	Net cash flow provided by operating activities	$	163,353			$	656		$	49,271		$	—		$	14,447		$	227,727
	Capital expenditures	(231,934		)		(656		)	(242,158		)	—			(10,731		)	(485,479		)
	Proceeds from Crestwood earn-out	41,097				—			—			—			—			41,097
	Proceeds from sale of properties and equipment	72,362				—			363			—			—			72,725
	Net cash flow used in investing activities	(118,475		)		(656		)	(241,795		)	—			(10,731		)	(371,657		)
	Issuance of debt	228,500				—			239,459			—			—			467,959
Repayments of debt	(264,018		)		—			(46,412		)	—			—			(310,430		)
Debt issuance costs	(1,972		)		—			(1,050		)	—			—			(3,022		)
Distribution of Fortune Creek Partnership funds	—				—			—			—			(14,285		)	(14,285		)
Proceeds from exercise of stock options	11				—			—			—			—			11
Purchase of treasury stock	(3,144		)		—			—			—			—			(3,144		)
Net cash flow provided by (used in) financing activities	(40,623		)		—			191,997			—			(14,285		)	137,089
Effect of exchange rates on cash	—				—			527			—			(1,881		)	(1,354		)
Net increase (decrease) in cash and equivalents	4,255				—			—			—			(12,450		)	(8,195		)
Cash and equivalents at beginning of period	363				—			—			—			12,783			13,146
Cash and equivalents at end of period	$	4,618			$	—		$	—		$	—		$	333		$	4,951

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Operating Income And Property And Equipment Costs Incurred
		Exploration & Production						Midstream									Quicksilver
		U.S.			Canada						Corporate			Elimination			Consolidated
		(in thousands)
	2014
	Revenue	$	410,444		$	150,876		$	25,693		$	—		$	(17,585	)	$	569,428
	DD&A	30,411			23,902			4,970			1,843			—			61,126
	Impairment expense	2,450			11,043			58,495			—			—			71,988
	Operating income (loss)	156,382			22,601			(44,412		)	(49,137		)	—			85,434
	Property and equipment costs incurred	100,592			27,585			86			1,127			—			129,390
	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
	Property, plant and equipment—net
	31-Dec-14	$	416,901		$	280,830		$	27,205		$	3,844		$	—		$	728,780
	31-Dec-13	451,840			306,423			97,118			5,424			—			860,805
	Total assets
	31-Dec-14	$	881,906		$	285,695		$	42,857		$	3,844		$	—		$	1,214,302
	31-Dec-13	895,388			359,951			108,963			5,424			—			1,369,726

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Cash Paid Or Received For Interest And Income Taxes
		Years Ended December 31,
		2014			2013		2012
		(in thousands)
	Interest, net of capitalized interest	$	152,983		$	254,901	$	154,663
	Income taxes, net	(7,051		)	833		(20,682		)
Other Significant Non-cash Transactions
		Years Ended December 31,
		2014			2013		2012
		(in thousands)
	Working capital related to capital expenditures	$	4,666		$	10,324	$	10,939

Supplemental_Selected_Quarterl1

Supplemental Selected Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
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)
	2014 (1)
	Operating revenue	$	91,786		$	118,032		$	163,498	$	196,112
	Operating income (loss)	(11,054		)	13,536			64,784		18,168
	Net income (loss)	(58,833		)	(36,095		)	23,757		(31,929		)
	Basic net earnings per share	$	(0.34	)	$	(0.21	)	$	0.13	$	(0.18	)
	Diluted net earnings per share	(0.34		)	(0.21		)	0.13		(0.18		)
	2013 (2) (3) (4)
	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		)
	(1)	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
	(2)	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.
	(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 $8.0 million arising from a change to the amount of unevaluated properties allocated to TGBR.
	(4)	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.

Nature_Of_Operations_Nature_of

Nature Of Operations Nature of Operations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Available borrowing under combined credit agreements	$9.20
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Borrowing capacity	325
Subsequent Event [Member] | Senior Notes Due Two Thousand Nineteen [Member]
Debt Instrument [Line Items]
Debt Instrument, Periodic Payment, Interest	$13.60

Significant_Accounting_Policie2

Significant Accounting Policies (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	customers	customers	customers
Significant Accounting Policies [Line Items]
Inventories	$8,269,000	$18,334,000
Inventory Impairments	7030	2998
Foreign Currency Transaction Gain (Loss), before Tax	-3,700,000	-2,400,000
Purchasers	2	1	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	17.00%	18.00%	21.00%
Purchaser Two [Member]
Significant Accounting Policies [Line Items]
Purchases made by customer percentage	13.00%		15.00%
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
materials and parts [Member]
Significant Accounting Policies [Line Items]
Inventories	7,600,000	15,800,000
NGLs [Member]
Significant Accounting Policies [Line Items]
Inventories	$700,000	$2,500,000

Divestitures_Narrative_Details

Divestitures (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended	3 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2014	Sep. 30, 2013	Dec. 28, 2012	1-May-14	Apr. 30, 2013
	acre			acre
Acquisitions And Divestitures [Line Items]
Approximate Gross Acres Eni West Texas Total	52,500
Percentage of ownership interest		100.00%
Eni Funding of West Texas Transaction		$52
Joint Interest Ownership After Complete Three Phases	50.00%
Sandwash Basin [Member]
Acquisitions And Divestitures [Line Items]
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds					95.6
Southern Alberta Basin [Member]
Acquisitions And Divestitures [Line Items]
PurchasePricePriorToAdjustments	46
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	42.3
Barnett Shale [Member]
Acquisitions And Divestitures [Line Items]
Percentage of ownership interest						25.00%
PurchasePricePriorToAdjustments						485
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds						464
Significant Acquisitions and Disposals, Gain (Loss) on Sale or Disposal, Pretax						339.3
Tokyo Gas [Member]
Acquisitions And Divestitures [Line Items]
Oil and Gas Property Decrease due to Gain			$110.70
Acquisition and Exploration Agreement [Member] | SWEPI LP [Member]
Acquisitions And Divestitures [Line Items]
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%
Equalization Payment Percentage				50.00%

Derivatives_And_Fair_Value_Mea2

Derivatives And Fair Value Measurements (Narrative) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2010
	MMcf
Anticipated Natural Gas Production for 2015 - subsequent to year-end	20
Anticipated Natural Gas Production Thereafter - subsequent to year-end	0
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	22.4
Reduction of interest expense over the life of a debt instruments	2.8
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	2	12
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	4.6
Fair Value, Inputs, Level 3 [Member] | Minimum [Member]
Unobservable inputs included within the fair value calculation	2.88
Subsequent Event [Member]
Cash Proceeds From Derivative Terminations	$135.70

Derivatives_And_Fair_Value_Mea3

Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments Under Input Levels) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	$149,567	$130,880
Asset Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	104,608	107,395
Asset Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	44,959	23,485
Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	0	3,448
Liability Derivatives [Member] | Fair Value Inputs, Level 2 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	0	3,448
Liability Derivatives [Member] | Fair Value Inputs, Level 3 [Member] | Commodity Contracts [Member]
Derivatives, Fair Value [Line Items]
Estimated fair value of derivative instruments	$0	$0

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, 2014	Dec. 31, 2013
Balance at beginning of period	($23,485)	$4,931
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Gain (Loss) Included in Earnings	-31,824	-40,398
Transfers out of Level 3	-3,559	0
Balance at end of period	-44,959	-23,485
Total gains included in net derivative gains attributable to the change in unrealized gains related to assets still held at the reporting date	32,074	41,909
Derivative gains (losses) [Member]
Settlements	($6,791)	($11,982)

Derivatives_And_Fair_Value_Mea5

Derivatives And Fair Value Measurements (Swaps For Anticipated Natural Gas and NGL Production) (Details)	12 Months Ended
	Dec. 31, 2014
	MMcf
Credit Risk Derivatives, at Fair Value, Net [Abstract]
Gas 2015	150
Gas 2016-2021	30

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, 2014
Credit Risk Derivatives, at Fair Value, Net [Abstract]
2015	$33,191
2016	13,476
2017	12,531
2018	11,664
2019 and thereafter	29,779
Net deferred hedge gain in AOCI to be released into earnings	$100,641

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, 2014
Credit Risk Derivatives, at Fair Value, Net [Abstract]
2015	$2,194
2016	569
Reduction of interest expense over the life of the debt instruments, total	$2,763

Derivatives_And_Fair_Value_Mea8

Derivatives And Fair Value Measurements (Estimated Fair Value Of Derivative Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]
Current derivative assets	$120,176	$57,523
Noncurrent derivative assets	29,391	73,357
Current derivative liabilities	0	3,125
Noncurrent derivative liabilities	0	323
Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative assets	201,363	165,378
Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Total derivative liabilities	51,796	37,946
Not Designated as Hedging Instrument [Member] | Asset Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	120,176	60,063
Noncurrent derivative assets	81,187	105,315
Current derivative liabilities	0	0
Noncurrent derivative liabilities	0	0
Not Designated as Hedging Instrument [Member] | Liability Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	0	2,540
Noncurrent derivative assets	51,796	31,958
Current derivative liabilities	0	3,125
Noncurrent derivative liabilities	$0	$323

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivatives, Fair Value [Line Items]
Settlements in production revenue	$24,702	$46,931	$128,161

Recovered_Sheet1

Derivatives And Fair Value Measurements Derivatives, Investments And Fair Value Measurements (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2014
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Sold Security, at Carrying Value		$10,000,000
Held-to-maturity Securities, Transferred Security, at Carrying Value		10,000,000
Fixed Income Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Fair Value	29,397,000
Held-to-maturity Securities, Unrecognized Holding Loss	-22,000
Held-to-maturity Securities, Unrecognized Holding Gain	0
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	29,419,000
Commercial Paper, Not Included with Cash and Cash Equivalents [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Fair Value	136,926,000
Held-to-maturity Securities, Unrecognized Holding Loss	-25,000
Held-to-maturity Securities, Unrecognized Holding Gain	27,000
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	136,924,000
Debt Securities [Member]
Schedule of Held-to-maturity Securities [Line Items]
Held-to-maturity Securities, Fair Value	166,323,000
Held-to-maturity Securities, Unrecognized Holding Loss	-47,000
Held-to-maturity Securities, Unrecognized Holding Gain	27,000
Held-to-maturity Securities, Amortized Cost before Other than Temporary Impairment	$166,343,000

Accounts_Receivable_Schedule_O

Accounts Receivable (Schedule Of Accounts Receivable) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accounts Receivable, Net [Abstract]
Accrued production	$32,130	$34,785
Joint interest billings	22,621	15,630
Income taxes	7,574	7,931
Canadian value added taxes	173	60
Other	2,937	328
Allowance for doubtful accounts	-277	-89
Accounts receivable, net	$65,158	$58,645

Other_Current_Assets_Details

Other Current Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Current Assets [Abstract]
Inventories	$8,269	$18,334
Deposits	1,284	1,044
Other prepaid expense	4,861	2,968
Other current assets	$14,414	$22,346

Property_Plant_And_Equipment_N

Property, Plant And Equipment (Narrative) (Details) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
				Rate
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%
Impairment expense	$71,900,000	$71,988,000	$1,863,000	$2,625,928,000
Capitalized overhead costs related to exploration and development activities		11,200,000	13,600,000	16,800,000
Depreciation Expense		15,200,000	17,100,000	18,600,000
U.S. [Member]
Property, Plant and Equipment [Line Items]
Impairment expense		2,450,000	1,809,000	2,152,665,000
Depletion per Mcfe		0.48	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		11,043,000	0	465,935,000
Depletion per Mcfe		0.38	0.14	0.83
Midstream [Member] | U.S. [Member] | Other Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairment expense		135,000	54,000	7,328,000
Midstream [Member] | Canada [Member] | Other Property and Equipment [Member]
Property, Plant and Equipment [Line Items]
Impairment expense		$58,360,000	$0	$0

Property_Plant_And_Equipment_S

Property, Plant And Equipment (Schedule Of Property, Plant And Equipment) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment [Abstract]
Subject to depletion	$5,821,167	$5,687,557
Unevaluated costs of oil and natural gas properties	18,803	221,605
Accumulated depletion	-5,225,302	-5,268,719
Net oil and gas properties	614,668	640,443
Pipelines and processing facilities	316,013	347,093
General properties	66,455	72,125
Accumulated depreciation	-268,356	-198,856
Property, Plant and Equipment, Other, Net	114,112	220,362
Property, plant and equipment - net	$728,780	$860,805

Property_Plant_And_Equipment_S1

Property, Plant And Equipment (Schedule Of Charges For Impairment) (Details) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Impairment expense	$71,900	$71,988	$1,863	$2,625,928
U.S. [Member]
Impairment expense		2,450	1,809	2,152,665
Canada [Member]
Impairment expense		11,043	0	465,935
Exploration and Production Equipment [Member] | Oil and Gas Properties [Member] | U.S. [Member]
Impairment expense		0	0	2,152,128
Exploration and Production Equipment [Member] | Oil and Gas Properties [Member] | Canada [Member]
Impairment expense		0	0	465,935
Exploration and Production Equipment [Member] | Other Property and Equipment [Member] | U.S. [Member]
Impairment expense		2,450	1,809	537
Exploration and Production Equipment [Member] | Other Property and Equipment [Member] | Canada [Member]
Impairment expense		11,043	0	0
Midstream [Member] | Other Property and Equipment [Member] | U.S. [Member]
Impairment expense		135	54	7,328
Midstream [Member] | Other Property and Equipment [Member] | Canada [Member]
Impairment expense		$58,360	$0	$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, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Total	$18,803	$221,605
Current Year [Member]
Property, Plant and Equipment [Line Items]
Total	6,032	12,098
Before Current Year [Member]
Property, Plant and Equipment [Line Items]
Total	961	42,177
Before Previous Year [Member]
Property, Plant and Equipment [Line Items]
Total	2,781	59,398
Prior [Member]
Property, Plant and Equipment [Line Items]
Total	9,029	107,932
U.S. [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	16,240	16,497
Exploration costs	0	378
Capitalized interest	2,563	2,467
Total	18,803	19,342
U.S. [Member] | Current Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	5,637	0
Exploration costs	0	14
Capitalized interest	395	1,093
Total	6,032	1,107
U.S. [Member] | Before Current Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	3,013
Exploration costs	0	364
Capitalized interest	961	1,374
Total	961	4,751
U.S. [Member] | Before Previous Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	1,574	13,484
Exploration costs	0	0
Capitalized interest	1,207	0
Total	2,781	13,484
U.S. [Member] | Prior [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	9,029	0
Exploration costs	0	0
Capitalized interest	0	0
Total	9,029	0
Canada [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	72,842
Exploration costs	0	110,295
Capitalized interest	0	19,126
Total	0	202,263
Canada [Member] | Current Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	0
Exploration costs	0	7,044
Capitalized interest	0	3,947
Total	0	10,991
Canada [Member] | Before Current Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	2,956
Exploration costs	0	31,746
Capitalized interest	0	2,724
Total	0	37,426
Canada [Member] | Before Previous Year [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	1,300
Exploration costs	0	41,092
Capitalized interest	0	3,522
Total	0	45,914
Canada [Member] | Prior [Member]
Property, Plant and Equipment [Line Items]
Acquisition costs	0	68,586
Exploration costs	0	30,413
Capitalized interest	0	8,933
Total	$0	$107,932

Property_Plant_And_Equipment_S3

Property, Plant And Equipment (Schedule Of Unevaluated Property Costs) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Total	$18,803	$221,605
West Texas [Member]
Total	18,803	19,343
Horn River Asset [Member]
Total	$0	$202,262

Other_Assets_Schedule_Of_Other

Other Assets (Schedule Of Other Assets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Other Assets, Noncurrent Disclosure [Abstract]
Deferred financing costs	$62,319	$84,951
Less accumulated amortization	-33,472	-50,171
Net deferred financing costs	28,847	34,780
Notes receivable	3,888	6,464
Other	119	360
Other assets, total	$32,854	$41,604

Accrued_Liabilities_Schedule_O

Accrued Liabilities (Schedule Of Accrued Liabilities) (Details) New (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Accrued Liabilities [Abstract]
Interest payable	$36,288	$38,260
Accrued operating expenses	21,833	37,747
Prepayments from partners	0	425
Revenue payable	19,121	22,589
Accrued state income and franchise taxes	55	1,080
Accrued production and property taxes	677	870
Environmental liabilities	18	36
Accrued product purchases	310	270
Current asset retirement obligations	967	433
Other	1,877	1,140
Accrued liabilities, total	$81,146	$102,850

LongTerm_Debt_Narrative_Detail

Long-Term Debt (Narrative) (Details) (USD $)	12 Months Ended			2 Months Ended	3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Aug. 21, 2013	Dec. 31, 2013	Jun. 30, 2009	Sep. 30, 2013	Sep. 30, 2009	Jun. 30, 2008	Aug. 31, 2009	Dec. 31, 2006
						Rate			Rate	Rate	Rate
Debt Instrument [Line Items]
Premium and Tender Premium Paid		$51,400,000
Percentage of ownership interest	100.00%
Interest Expense	163,286,000	251,847,000	164,051,000
Interest Costs Capitalized	-5,700,000	-7,700,000
Payments of Financing Costs		23,400,000
Debt Issuance Cost		4,100,000
Repayments of Long-term Debt	193,689,000	1,308,382,000	310,430,000
Issuance of debt	243,184,000	1,237,352,000	467,959,000
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	0	10,825,000			10,825,000
Repayments of Long-term Debt	8,900,000
Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount	0	2,149,000			2,149,000
Repayments of Long-term Debt	10,900,000
Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement	100,000,000
Debt Instrument, Unamortized Discount	14,758,000	0			0
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Borrowing capacity	325,000,000
Line of Credit Facility, Maximum Borrowing Capacity	450,000,000	1,750,000,000			1,750,000,000
Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Percentage of ownership interest	100.00%
Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		625,000,000			625,000,000
Debt Issue Percentage		97.00%			97.00%
Issuance of debt		606,300,000
Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		200,000,000			200,000,000
Debt Issue Percentage		97.00%			97.00%
Issuance of debt		194,000,000
Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage									8.25%
Debt Instrument, Face Amount		438,000,000			438,000,000				475,000,000
Repayments of Long-term Debt				450,700,000	2,300,000
Debt Issue Percentage									98.66%
Long Term Debt Repurchase Price		1,027.90			1,027.90
Interest Paid on Repurchased Debt		32.08			32.08
Debt Instrument, Repurchase Amount		1,000			1,000
Amount Tendered		425,200,000			425,200,000
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Available borrowing under combined credit agreements	9,200,000
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage						11.75%
Debt Instrument, Face Amount		590,600,000			590,600,000	600,000,000
Repayments of Long-term Debt				654,400,000
Debt Issue Percentage						96.72%
Issuance of debt						580,300,000
Long Term Debt Repurchase Price		1,068			1,068
Interest Paid on Repurchased Debt		55.49			55.49
Debt Instrument, Repurchase Amount		1,000			1,000
Amount Tendered		582,500,000			582,500,000
Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage										9.13%
Consent Fee							11,500,000
Debt Instrument, Face Amount										300,000,000
Debt Issue Percentage										97.61%
Issuance of debt								292,800,000
Senior Notes Due Two Thousand Twenty-one [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		11.00%			11.00%
Debt Instrument, Face Amount		325,000,000			325,000,000
Debt Issue Percentage		94.93%			94.93%
Issuance of debt		308,500,000
Senior Subordinated Notes Due 2016 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage											7.13%
Debt Instrument, Face Amount											350,000,000
Maximum [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Maximum [Member] | Global Letter Of Credit [Member]
Debt Instrument [Line Items]
Borrowing capacity	280,000,000
Minimum [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant, EBITDA to Interest Expense	2.25
Minimum [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Multiple Subsidiaries Set One [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Percentage of ownership interest	100.00%
Multiple Subsidiaries Set Two [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Percentage of ownership interest	65.00%
CDOR Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%
CDOR Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Canadian Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Canadian Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
U S Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
U S Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%
Alternative Base Rate [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		4.75%
Floor on Debt Rate		2.25%			2.25%
London Interbank Offered Rate (LIBOR) [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%
London Interbank Offered Rate (LIBOR) [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		5.75%
Floor on Debt Rate		1.25%			1.25%
London Interbank Offered Rate (LIBOR) [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate		5.75%
Floor on Debt Rate		1.25%			1.25%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	3.75%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | U S Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.75%
Senior Notes [Member] | 2013 [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	105.88%
Senior Notes [Member] | 2013 [Member] | Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.94%
Subsequent Event [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Proceeds From Derivative Terminations Used to Pay Debt	36,700,000
Subsequent Event [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Debt Instrument, Periodic Payment, Interest	$13,600,000

LongTerm_Debt_Schedule_Of_Long

Long-Term Debt (Schedule Of Long-Term Debt Instruments) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Combined Credit Agreements	$41,300,000
Long-term Debt	2,034,542,000	1,984,144,000
Unamortized deferred gain - terminated interest rate swaps	2,763,000	4,802,000
Long-term Debt, Current Maturities	2,037,305,000	0
Long-term debt	0	1,988,946,000
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Combined Credit Agreements	274,514,000	211,200,000
Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Senior notes	0	10,472,000
Debt Instrument, Unamortized Discount	0	2,149,000
Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Senior notes	0	8,044,000
Debt Instrument, Unamortized Discount	0	10,825,000
Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Senior notes	293,919,000	293,243,000
Debt Instrument, Unamortized Discount	4,081,000	5,378,000
Senior Notes Due Two Thousand Twenty-one [Member]
Debt Instrument [Line Items]
Senior notes	310,590,000	309,190,000
Debt Instrument, Unamortized Discount	14,410,000	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	610,242,000	607,572,000
Debt Instrument, Unamortized Discount	14,758,000	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	195,277,000	194,423,000
Debt Instrument, Unamortized Discount	4,723,000	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, 2014
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	624,514
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	1,123,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	325,000
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	274,514
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 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	200,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
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	625,000
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	298,000
Long-term Debt, Maturities, Repayments of Principal after Year Five	0
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	350,000
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

LongTerm_Debt_Schedule_Of_Outs

Long-Term Debt (Schedule Of Outstanding Debt) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Debt Instrument [Line Items]
Equity interests	100.00%
Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement	100
Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Secured Second Lien Repayment Term Triggering Event Related To Senior Notes Due 2019, Maximum Threshold For Measurement	100
Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	100.00%
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	325
Multiple Subsidiaries Set One [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	100.00%
Multiple Subsidiaries Set Two [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Equity interests	65.00%
Maximum [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
Minimum [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.75%
Senior Subordinated Notes [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Principal amount	350
Scheduled maturity date	1-Apr-16
Debt Instrument, Potential Earliest Maturity Date	N/A
Interest rate on outstanding borrowings at June 30, 2012	7.13%
Base interest rate options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[1],[2]
Optional redemption	Any time	[1]
Make-whole redemption	N/A
Equity Clawback	N/A
Change of control	Put at 101% of principal plus accrued interest	[1]
Estimated fair value	26.5	[3]
Percentage of principal plus accrued interest for change of control	101.00%
First Mortgage [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Current ratio	1
Minimum EBITDA to cash interest expense ratio	1.1
Senior secured debt leverage ratio	2
Line of Credit Facility, Current Borrowing Capacity	325	[4],[5]
Scheduled maturity date	6-Sep-16	[6]
Debt Instrument, Potential Earliest Maturity Date	2-Oct-15	[6]
Interest rate on outstanding borrowings at June 30, 2012	4.10%	[7]
Base interest rate options	LIBOR, ABR, CDOR	[8],[9]
Financial covenants	- Minimum current ratio of 1.0 - Minimum EBITDAX or EBITDA to cash interest expense - Maximum senior secured debt leverage ratio of 2.0	[1],[10]
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens - Payment of dividends - Equity purchases - Asset sales - Affiliate transactions - Limitations on derivatives and investments	[1],[2]
Optional redemption	Any time	[1]
Make-whole redemption	N/A
Equity Clawback	N/A
Change of control	Event of default	[1]
Estimated fair value	274.5	[3]
Second Mortgage [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Principal amount	625	[4]
Scheduled maturity date	21-Jun-19	[6]
Debt Instrument, Potential Earliest Maturity Date	1-Jan-16	[6]
Interest rate on outstanding borrowings at June 30, 2012	7.00%
Base interest rate options	LIBOR floor of 1.25%; ABR floor of 2.25%
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[1],[2]
Optional redemption	Any time, subject to re-pricing event June 21, 2015: 101	[1]
Make-whole redemption	N/A
Equity Clawback	N/A
Change of control	Put at 101% of principal plus accrued interest	[1]
Estimated fair value	465.6	[3]
Percentage of principal plus accrued interest for change of control	101.00%
Second Mortgage [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Principal amount	200	[4]
Scheduled maturity date	21-Jun-19	[6]
Debt Instrument, Potential Earliest Maturity Date	1-Jan-16	[6]
Interest rate on outstanding borrowings at June 30, 2012	7.00%
Base interest rate options	LIBOR floor of 1.25%
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens and 1st lien cap -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[1],[2]
Optional redemption	Any time, subject to re-pricing event June 21, 2015: 101	[1]
Make-whole redemption	N/A
Equity Clawback	N/A
Change of control	Put at 101% of principal plus accrued interest	[1]
Estimated fair value	149	[3]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Notes [Member] | Senior Notes Due Two Thousand Twenty-one [Member]
Debt Instrument [Line Items]
Principal amount	325
Scheduled maturity date	1-Jul-21
Debt Instrument, Potential Earliest Maturity Date	N/A
Interest rate on outstanding borrowings at June 30, 2012	11.00%
Base interest rate options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[1],[2]
Optional redemption	July 1, 2019: 102.000 2020: par	[1]
Make-whole redemption	Callable prior to July 1, 2019 at make-whole call price of Treasury +50 bps	[1]
Equity Clawback	Redeemable until July 1, 2016 at 111.00%, plus accrued interest for up to 35%	[1]
Change of control	Put at 101% of principal plus accrued interest	[1]
Estimated fair value	87.9	[3]
Make-whole redemption treasury plus percentage	0.50%
Percentage of principal plus accrued interest for change of control	101.00%
Equity Clawback Redemption Percentage	111.00%
Senior Notes [Member] | Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Notes [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Percentage of principal plus accrued interest for change of control	101.00%
Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Principal amount	298
Scheduled maturity date	15-Aug-19
Debt Instrument, Potential Earliest Maturity Date	N/A
Interest rate on outstanding borrowings at June 30, 2012	9.13%
Base interest rate options	N/A
Financial covenants	N/A
Significant restrictive covenants	- Incurrence of debt - Incurrence of liens -Payment of dividends - Equity purchases - Asset sales - Affiliate transactions	[1],[2]
Optional redemption	August 15, 2014: 104.563 2015: 103.042 2016: 101.521 2017: par	[1]
Make-whole redemption	N/A
Equity Clawback	N/A
Change of control	Put at 101% of principal plus accrued interest	[1]
Estimated fair value	74.8	[3]
Make-whole redemption treasury plus percentage	0.50%
Percentage of principal plus accrued interest for change of control	101.00%
CDOR Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	3.75%
CDOR Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.00%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	3.75%
London Interbank Offered Rate (LIBOR) [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	3.75%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | U.S. Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
London Interbank Offered Rate (LIBOR) [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Reference Rate, Floor	1.25%
London Interbank Offered Rate (LIBOR) [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	1.25%
Canadian Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
Canadian Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.75%
U.S. Prime Rate [Member] | Maximum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	2.75%
U.S. Prime Rate [Member] | Minimum [Member] | Canadian Credit Facility [Member]
Debt Instrument [Line Items]
Applicable margin in addition to interest rate	1.75%
ABR [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Debt Instrument, Reference Rate, Floor	2.25%
2013 [Member] | Senior Subordinated Notes [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.19%
2013 [Member] | Senior Notes [Member] | Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.94%
Percentage of principal plus accrued interest for change of control	101.94%
2013 [Member] | Senior Notes [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	105.88%
2014 [Member] | Senior Subordinated Notes [Member] | Senior Subordinated Notes [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
2014 [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.00%
2014 [Member] | Senior Notes [Member] | Senior Notes Due 2015 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
2014 [Member] | Senior Notes [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.94%
2014 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	104.56%
2015 [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.00%
2015 [Member] | Second Mortgage [Member] | Senior Secured Second Lien Term Loan Due 2019 [Member]
Debt Instrument [Line Items]
Percentage of principal plus accrued interest for change of control	101.00%
2015 [Member] | Senior Notes [Member] | Senior Notes Due 2016 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
2015 [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	103.04%
Year Twenty Sixteen [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	101.52%
Year Twenty Seventeen [Member] | Senior Notes [Member] | Senior Notes Due 2019 [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
Year Twenty Nineteen [Member] | Senior Notes [Member] | Senior Notes Due Two Thousand Twenty-one [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	102.00%
Year Twenty Twenty [Member] | Senior Notes [Member] | Senior Notes Due Two Thousand Twenty-one [Member]
Debt Instrument [Line Items]
Redemption percentage of par value	100.00%
Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
Combined Credit Agreements [Member] | Maximum [Member]
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
First Quarter Two Thousand Sixteen [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1.5
Three Months Ended December 31, 2014 [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	30
Six months ending March 31, 2015 [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	59
Nine months ending June 30, 2015 [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	87.25
Twelve months ending September 30, 2015 [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	120.5
Twelve months ending December 31, 2015 [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	122
Second Quarter Two Thousand Sixteen [Member] | Minimum [Member] | Combined Credit Agreements [Member]
Debt Instrument [Line Items]
Interest coverage ratio	2
[1]	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.
[2]	Our indentures require us to reinvest or repay senior debt with net cash proceeds from certain asset sales within one year.
[3]	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 and a first priority lien to have a fair value equal to their carrying value (bLevel 1b input).
[4]	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 natural 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 natural gas properties and related assets. The other debt presented is based upon structural seniority and priority of payment.
[5]	The principal amount for the Combined Credit Agreements represents the global borrowing base as of DecemberB 31, 2014.
[6]	The Combined Credit Agreements are required to be repaid 91 days prior to the maturity of the 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 Senior Subordinated Notes if on the applicable date the amount remaining outstanding is greater than $100 million. As of DecemberB 31, 2014, as then structured and assuming no changes in the amounts outstanding, amounts outstanding under the Combined Credit Agreements would have been due on October 2, 2015 and the Second Lien Term Loan and Second Lien Notes due 2019 would have been due on January 1, 2016.
[7]	Represents the weighted average borrowing rate payable to lenders.
[8]	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%.
[9]	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%.
[10]	As of DecemberB 31, 2014, the minimum EBITDAX covenant for the Combined Credit Agreements is as follows:B Minimum EBITDAX CovenantB (in millions)Three months ending December 31, 2014$30.0Six months ending March 31, 201559.0Nine months ending June 30, 201587.25Twelve months ending September 30, 2015120.5Twelve months ending December 31, 2015122.0The minimum required interest coverage ratio for the Combined Credit Agreements for first quarter of 2016 and second quarter of 2016 is 1.50 and 2.00, respectively.

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, 2014
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

LongTerm_Debt_LongTerm_Debt_Mi1

Long-Term Debt Long-Term Debt (Minimum EBITDAX Covenant) (Details) (Minimum [Member], Combined Credit Agreements [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Three Months Ended December 31, 2014 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	$30
Six months ending March 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	59
Nine months ending June 30, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	87.25
Twelve months ending September 30, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	120.5
Twelve months ending December 31, 2015 [Member]
Debt Instrument [Line Items]
Minimum EBITDAX Covenant	$122

LongTerm_Debt_LongTerm_Debt_QR

Long-Term Debt Long-Term Debt (QRI & Restricted Subsidiaries Indenture Financials (Balance Sheet) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Indenture Disclosure Financials [Line Items]
Property, Plant and Equipment, Net	$728,780	$860,805
Equity Method Investments	0	0
Other Noncurrent Assets	62,245	114,961
Total assets	1,214,302	1,369,726
Liabilities, Current	2,141,037	134,797
Liabilities, Noncurrent	211,136	2,240,899
Stockholders' equity	-1,137,871	-1,005,970
Total liabilities and stockholders' equity	1,214,302	1,369,726
Assets, Current	423,277	393,960
Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Property, Plant and Equipment, Net	715,931	779,173
Equity Method Investments	-82,360	-33,840
Other Noncurrent Assets	62,245	114,961
Total assets	1,117,349	1,254,007
Liabilities, Current	2,137,532	134,010
Liabilities, Noncurrent	117,688	2,113,221
Stockholders' equity	-1,137,871	-993,224
Total liabilities and stockholders' equity	1,117,349	1,254,007
Assets, Current	$421,533	$393,713

LongTerm_Debt_LongTerm_Debt_QR1

Long-Term Debt Long-Term Debt (QRI & Restricted Subsidiaries Indenture Financials (Income Stmt) (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Indenture Disclosure Financials [Line Items]
Oil and Gas Revenue													$569,428	$561,562	$709,038
Operating Expenses													483,994	436,246	3,215,896
Equity Method Investment, Summarized Financial Information, Income (Loss) from Continuing Operations before Extraordinary Items													0	0	0
Operating Income (Loss)	18,168	[1]	64,784	13,536	-11,054	13,575	[2]	60,049	[3]	394,894	[4]	-3,874	85,434	464,644	-2,465,761
Accretion Expense													-15,067	-19,245	-19,472
Interest expense and other													-169,867	-269,231	-162,943
Income tax (expense) benefit													-3,600	-14,550	295,570
Net income (loss)													-103,100	161,618	-2,352,606
Other Comprehensive Income, Other, Net of Tax													-38,028	-51,612	-53,365
Equity in other comprehensive income of subsidiaries													0	0	0
Comprehensive income (loss)													-141,128	110,006	-2,405,971
Tokyo Gas [Member]
Indenture Disclosure Financials [Line Items]
Gain on Tokyo Gas Transaction										333,200			0	339,328	0
kwk_CrestwoodLP [Member]
Indenture Disclosure Financials [Line Items]
Crestwood earn-out													0	0	41,097
Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Oil and Gas Revenue													569,428	561,562	709,038
Operating Expenses													434,998	448,802	3,222,595
Equity Method Investment, Summarized Financial Information, Income (Loss) from Continuing Operations before Extraordinary Items													-64,056	-6,682	-12,747
Operating Income (Loss)													70,374	445,406	-2,485,207
Interest expense and other													-169,874	-269,238	-162,991
Income tax (expense) benefit													-3,600	-14,550	295,592
Net income (loss)													-103,100	161,618	-2,352,606
Other Comprehensive Income, Other, Net of Tax													-38,028	-51,612	-53,365
Comprehensive income (loss)													-141,128	110,006	-2,405,971
Quicksilver And Restricted Subsidiaries [Member] | Tokyo Gas [Member]
Indenture Disclosure Financials [Line Items]
Gain on Tokyo Gas Transaction													0	339,328	0
Quicksilver And Restricted Subsidiaries [Member] | kwk_CrestwoodLP [Member]
Indenture Disclosure Financials [Line Items]
Crestwood earn-out													$0	$0	$41,097
[1]	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
[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 $8.0 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.

LongTerm_Debt_LongTerm_Debt_QR2

Long-Term Debt Long-Term Debt (QRI & Restricted Subsidiaries Indenture Financials (Cash Flow) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Indenture Disclosure Financials [Line Items]
Net Cash Provided by (Used in) Operating Activities	($7,629)	($51,700)	$227,727
Purchases of property, plant and equipment	-133,481	-101,288	-485,479
Investment in subsidiary	0
Proceeds from sale of properties and equipment	3,222	7,171	72,725
Payments to Acquire Marketable Securities	55,890	213,738	0
Proceeds from Sale and Maturity of Marketable Securities	222,025	47,603
Net cash used by investing activities	131,463	246,044	-371,657
Issuance of debt	243,184	1,237,352	467,959
Repayments of Long-term Debt	193,689	1,308,382	310,430
Payments of Debt Issuance Costs	1,705	26,296	3,022
Intercompany Note	0	0
Intercompany financing	0
Contribution received	0
Payments of Distributions to Affiliates	39,993	14,965	14,285
Proceeds from exercise of stock options	0	0	11
Payments Related to Tax Withholding for Share-based Compensation	2,388	1,927	3,144
Net Cash Provided by (Used in) Financing Activities	5,409	-114,218	137,089
Effect of exchange rates on cash	5,183	4,026	-1,354
Net increase (decrease) in cash and equivalents	134,426	84,152	-8,195
Cash and Cash Equivalents, at Carrying Value	223,529	89,103	4,951	13,146
Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Net Cash Provided by (Used in) Operating Activities	-13,614	-62,131	213,280
Purchases of property, plant and equipment	-133,481	-100,783	-474,748
Investment in subsidiary	-26,395	0	0
Proceeds from sale of properties and equipment	3,222	7,171	72,725
Payments to Acquire Marketable Securities	55,890	213,738	0
Proceeds from Sale and Maturity of Marketable Securities	222,025	47,603	0
Net cash used by investing activities	105,068	246,549	-360,926
Issuance of debt	243,184	1,237,352	467,959
Repayments of Long-term Debt	193,689	1,308,382	310,430
Payments of Debt Issuance Costs	1,705	26,296	3,022
Proceeds from exercise of stock options	0	0	11
Payments Related to Tax Withholding for Share-based Compensation	2,388	1,927	3,144
Net Cash Provided by (Used in) Financing Activities	45,402	-99,253	151,374
Effect of exchange rates on cash	-3,046	-1,755	527
Net increase (decrease) in cash and equivalents	133,810	83,410	4,255
Cash and Cash Equivalents, at Carrying Value	221,838	88,028	4,618	363
Sandwash Basin [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587	0	0
Sandwash Basin [Member] | Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587	0	0
Tokyo Gas [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,999	0
Tokyo Gas [Member] | Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,999	0
Synergy [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	42,297	0
Synergy [Member] | Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	42,297	0
kwk_CrestwoodLP [Member] | Quicksilver And Restricted Subsidiaries [Member]
Indenture Disclosure Financials [Line Items]
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	$0	$0	$41,097

Asset_Retirement_Obligations_E

Asset Retirement Obligations (Estimated Asset Retirement Obligation Activity) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation [Abstract]
Beginning asset retirement obligations	$106,689	$116,526
Additional liability incurred	269	3,922
Change in estimates	229	-7,582
Accretion expense	5,618	5,109
Asset retirement costs incurred	388	1,560
Gain on settlement of liability	-146	-742
Asset Retirement Obligations, Dispositions	1,778	21,935
Currency translation adjustment	-5,311	3,697
Ending asset retirement obligations	105,016	106,689
Less current portion	-967	-433
Long-term asset retirement obligation	$104,049	$106,256

Income_Taxes_Narrative_Details

Income Taxes (Narrative) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Rate
Federal statutory income tax rate	35.00%	35.00%	35.00%
State Statutory Rate	1.00%	1.00%	1.00%
Remaining net operating tax losses	$812,000,000	$529,000,000
Deferred Tax Assets, Tax Credit Carryforwards, Alternative Minimum Tax	40,309,000	47,883,000
Net Operating Loss, change in	283,000,000
Tax Valuation Allowance Expense, State	-1,632,000	3,680,000	0
U.S. federal valuation allowance expense	21,011,000	-186,713,000	533,974,000
Canadian valuation allowance expense	-2,634,000	1,647,000	61,325,000
Tax basis in fortune creek, net	29,000,000
Effective Income Tax Rate Reconciliation, Foreign Income Tax Rate Differential, Percent	1.40%	-0.26%	-1.93%
Valuation Allowance, Amount	434,108,000	417,595,000
Tax benefits recognized	0	0
CANADA
Foreign Statutory Rate, Canada	25.20%	25.20%	25.00%
UNITED STATES
Valuation Allowance, Deferred Tax Asset, Change in Amount	21,000,000
Canada [Member]
Valuation Allowance, Deferred Tax Asset, Change in Amount	-2,600,000
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-34
CANADA
Valuation Allowance, Amount	$3,700,000

Income_Taxes_Components_Of_Def

Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Components of Deferred Tax Assets and Liabilities [Abstract]
Property, plant and equipment	$148,360	$209,134
Net operating loss carry-forwards	289,261	183,982
Investment in Fortune Creek	3,763	3,763
AMT tax credit	40,309	47,883
Settlements of interest rate swaps	967	1,681
Deferred compensation expense	11,087	11,711
Deferred Tax Assets, State Taxes	2,048	3,680
Other	421	791
Deferred tax assets	496,216	462,625
Gains from hedging and derivative activities	-61,638	-44,039
Deferred Tax Liabilities, Other	-470	-991
Deferred tax liabilities	-62,108	-45,030
Net deferred tax asset (liability)	434,108	417,595
Valuation allowance	-434,108	-417,595
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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income (loss) before income taxes	($99,500)	$176,168	($2,648,176)
UNITED STATES
Income (Loss) from Continuing Operations before Income Taxes, Domestic	-41,865	184,034	-2,142,730
Income (loss) before income taxes	117,438	129,544	-1,955,773
Canada [Member]
Income (Loss) from Continuing Operations before Income Taxes, Foreign	-57,635	-7,866	-505,446
Income (loss) before income taxes	$36,769	$45,690	($459,288)

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Abstract]
Current state income tax expense (benefit)	($144)	$900	$1,752
Current U.S. federal income tax benefit	-7,574	-7,931	0
Current Canadian income tax expense	559	0	0
Total current income tax expense (benefit)	-7,159	-7,031	1,752
Deferred state income tax expense (benefit)	1,632	-3,680	0
Tax Valuation Allowance Expense, State	-1,632	3,680	0
Deferred U.S. federal income tax expense (benefit)	-11,238	205,820	-763,639
U.S. federal valuation allowance expense	21,011	-186,713	533,974
Deferred Canadian income tax expense (benefit)	3,620	827	-128,982
Canadian valuation allowance expense	-2,634	1,647	61,325
Total deferred income tax expense (benefit)	10,759	21,581	-297,322
Total income tax expense (benefit)	$3,600	$14,550	($295,570)

Income_Taxes_Statutory_Federal

Income Taxes (Statutory Federal Income Tax Rate) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012
		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%	35.00%
Permanent differences	-27.05%	-27.05%	4.80%	4.80%	-0.06%	-0.06%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	0.09%	0.09%	0.31%	0.31%	-0.04%	-0.04%
Canadian income taxes	1.40%	1.40%	-0.26%	-0.26%	-1.93%	-1.93%
Other	-0.30%	-0.30%	-0.15%	-0.15%	0.67%	0.67%
Derivatives deferred in OCI	-11.07%	-11.07%	12.43%	12.43%	0.00%	0.00%
Effective Income Tax Rate Reconciliation, AMT NOL refund, percent	7.61%	7.61%	0.00%	0.00%	0.00%	0.00%
Valuation allowance	-9.30%	-9.30%	-43.87%	-43.87%	-22.48%	-22.48%
Effective income tax rate	-3.62%	-3.62%	8.26%	8.26%	11.16%	11.16%

Commitments_And_Contingencies_1

Commitments And Contingencies (Narrative) (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
	USD ($)	USD ($)	Subsequent Event [Member]
			CAD
Loss Contingencies [Line Items]
Surety bonds	$6,400,000
Outstanding letters of credit	41,300,000
Accrual for Environmental Loss Contingencies	18,000	36,000
Letter of Credit Draw Down by Spectra			33,000,000
Gathering and Processing Potential Claim			126,000,000

Commitments_And_Contingencies_2

Commitments And Contingencies (Summary Of Contractual Obligations) (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Contractual Obligations [Line Items]
GPT Contracts, 2014	$72,995,000	[1]
GPT Contracts, 2015	69,566,000	[1]
GPT Contracts, 2016	66,492,000	[1]
GPT Contracts, 2017	60,453,000	[1]
GPT Contracts, 2018	44,241,000	[1]
GPT Contracts, Thereafter	95,250,000	[1]
GPT Contracts, Total	408,997,000	[1]
Drilling Rig Contracts, 2014	6,577,000	[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	6,577,000	[2]
Operating Leases, 2012	4,181,000	[3]
Operating Leases, 2013	4,275,000	[3]
Operating Leases, 2014	4,098,000	[3]
Operating Leases, 2015	3,961,000	[3]
Operating Leases, 2016	4,001,000	[3]
Operating Leases, Thereafter	8,849,000	[3]
Operating Leases, Total	29,365,000	[3]
Purchase Obligations, 2014	220,000	[4]
Purchase Obligations, 2015	0	[4]
Purchase Obligations, 2016	0	[4]
Purchase Obligations, 2017	0	[4]
Purchase Obligations, 2018	0	[4]
Purchase Obligations, Thereafter	0	[4]
Purchase Obligations, Total	220,000	[4]
Rent expense for operating leases	3,500,000		3,600,000	4,200,000
Operating Leases, Future Minimum Payments Due, Future Minimum Sublease Rentals	1,600,000
Minimum [Member]
Contractual Obligations [Line Items]
Drilling rig contracts outstanding payment	23,000
Maximum [Member]
Contractual Obligations [Line Items]
Drilling rig contracts outstanding payment	$24,300
[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 unused firm capacity 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 ranging from $23,000 to $24,300 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 $3.5 million in 2014, $3.6 million in 2013 and $4.2 million in 2012. Minimum payments have not been reduced by minimum sublease rentals of $1.6 million due in the future under noncancelable subleases.
[4]	At DecemberB 31, 2014, we were under contract to purchase goods and services.

Fortune_Creek_Details

Fortune Creek (Details) (CAD)	12 Months Ended
	Dec. 31, 2014
	in
	mi
	acre
	Y
Area of business, acres	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
Fortune Creek QRCI Compressor Purchase	33,000,000
Dedicated years for gas production	10
KKR [Member]
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			3 Months Ended
	15-May-13	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2013	Mar. 31, 2013	31-May-09	Jan. 31, 2008	Dec. 31, 2006
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				180,400,000
Immaterial Error Correction		5.9	8.2
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%
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		11,600,000	15,400,000
Accumulated Other Comprehensive Income (Loss), Net of Tax		$109,881,000		$71,853,000	$109,881,000
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to outstanding unvested awards				11,700,000
Share Based Compensation Nonvested Awards Total Compensation Cost Not Yet Recognized Period For Recognition				Dec-16
Compensation expense				10,500,000	16,800,000	15,700,000
Income tax benefit recognized related to compensation expense				3,200,000	5,200,000
Estimated grant date fair value				13,300,000
Fair value of RSUs settled in cash				200,000	4,800,000
Total fair value of shares vested				10,200,000	7,100,000	16,300,000
Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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				$8.07
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term				4 years 351 days
Unrecognized compensation cost related to outstanding unvested awards				500,000
Share Based Compensation Nonvested Awards Total Compensation Cost Not Yet Recognized Period For Recognition				Aug-16
Compensation expense				1,400,000	3,900,000	7,400,000
Income tax benefit recognized related to compensation expense				400,000	1,300,000
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value				0	0	100,000
Affiliated Entity [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage of ownership interest				25.00%
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax		94,500,000		69,800,000	94,500,000
Accumulated Translation Adjustment [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Accumulated Other Comprehensive Income (Loss), Net of Tax		$15,400,000		$2,100,000	$15,400,000
compensation expense correction [Domain]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Immaterial Error Correction					2.4	2.4	3.6	1.2

Quicksilver_Stockholders_Equit3

Quicksilver Stockholders' Equity (Common Shares And Treasury Share Activity) (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Common Stock, Shares, Issued	187,802,994	183,994,879
Treasury Stock, Shares	7,444,372	6,698,640
Common Stock [Member]
Schedule of Equity Method Investments [Line Items]
Common Stock, Shares, Issued	187,802,994	183,994,879	179,015,118	176,980,483
Stock options exercised	0	0	1,572
Restricted stock activity	3,808,115	4,979,761	2,033,063
Treasury Stock [Member]
Schedule of Equity Method Investments [Line Items]
Treasury Stock, Shares	7,444,372	6,698,640	5,921,102	5,379,702
Stock options exercised	0	0	0
Restricted stock activity	745,732	777,538	541,400

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
Share-based Compensation, Allocation and Classification in Financial Statements [Abstract]
Weighted avg grant date fair value	$1.05	$4.21
Weighted avg risk-free interest rate	1.31%	1.14%
Expected life (in years)	4 years 10 months 25 days	6 years
Wtd avg volatility	68.97%	68.20%
Expected dividends	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, 2014
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2013, Shares	6,771,578
Forfeited, Shares	-60,939
Expired, Shares	-119,866
Outstanding at December 31, 2013, Shares	6,590,773
Exercisable at December 31, 2013, Shares	5,224,531
Outstanding at January 1, 2013, Wtd Avg Exercise Price	$7.82
Forfeited, Wtd Avg Exercise Price	$3.04
Expired, Wtd Avg Exercise Price	$9.80
Outstanding at December 31, 2013, Wtd Avg Exercise Price	$7.83
Exercisable at December 31, 2013, Wtd Avg Exercise Price	$9.18
Outstanding at December 31, 2013, Wtd Avg Remaining Contractual Life, Years	5 years 37 days
Exercisable at December 31, 2013, Wtd Avg Remaining Contractual Life, Years	4 years 102 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, 2014
Payable In Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2013, Shares	5,668,090
Granted, Shares	6,070,563
Vested, Shares	-2,559,959
Forfeited, Shares	-1,122,429
Outstanding at December 31, 2013, Shares	8,056,265
Outstanding at January 1, 2013, Wtd Avg Grant Date Fair Value	$3.90
Granted, Wtd Avg Grant Date Fair Value	$2.19
Vested, Wtd Avg Grant Date Fair Value	$4.86
Forfeited, Wtd Avg Grant Date Fair Value	$2.26
Outstanding at December 31, 2013, Wtd Avg Grant Date Fair Value	$2.54
Payable In Cash [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at January 1, 2013, Shares	1,572,341
Granted, Shares	0
Vested, Shares	-636,146
Forfeited, Shares	-72,220
Outstanding at December 31, 2013, Shares	863,975
Outstanding at January 1, 2013, Wtd Avg Grant Date Fair Value	$3.69
Granted, Wtd Avg Grant Date Fair Value	$0
Vested, Wtd Avg Grant Date Fair Value	$4.27
Forfeited, Wtd Avg Grant Date Fair Value	$3.28
Outstanding at December 31, 2013, Wtd Avg Grant Date Fair Value	$3.33

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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Net income (loss) attributable to Quicksilver	($31,929)	$23,757	($36,095)	($58,833)	($31,775)	$10,577	$242,523	($59,707)	($103,100)	$161,618		($2,352,606)
Basic income allocable to participating securities									0	-4,252	[1]	0
Net Income (Loss) Available to Common Stockholders, Diluted									($103,100)	$157,366		($2,352,606)
Weighted average common shares - basic									173,822,000	171,518,000		170,106,000
Share-based compensation awards									0	141,000	[2]	0
Weighted average common shares - diluted									173,822,000	171,659,000		170,106,000
Earnings (loss) per common share - basic	($0.18)	$0.13	($0.21)	($0.34)	($0.18)	$0.06	$1.37	($0.35)	($0.59)	$0.92		($13.83)
Earnings (loss) per common share - diluted	($0.18)	$0.13	($0.21)	($0.34)	($0.18)	$0.06	$1.37	($0.35)	($0.59)	$0.92		($13.83)
Employee Stock Option [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive shares excluded from the diluted share calculation									6,600,000	5,600,000		5,000,000
Restricted Stock Units (RSUs) [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive shares excluded from the diluted share calculation									1,000,000	200,000		300,000
[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 2014, 6.6 million shares associated with our stock options and 1.0 million shares associated with our unvested restricted stock units were antidilutive and, therefore, excluded from the diluted share calculations. 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.

Condensed_Consolidating_Financ2

Condensed Consolidating Financial Information (Schedule Of Condensed Consolidated Balance Sheets) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Percentage of ownership interest	100.00%
Current assets	$423,277	$393,960
Property, plant and equipment	728,780	860,805
Investment in subsidiaries (equity method)	0	0
Other Noncurrent Assets	62,245	114,961
Total assets	1,214,302	1,369,726
Liabilities, Current	2,141,037	134,797
Long-term liabilities	211,136	2,240,899
Stockholders' equity	-1,137,871	-1,005,970
Total liabilities and stockholders' equity	1,214,302	1,369,726
Quicksilver Resources Inc. [Member]
Current assets	774,287	349,586
Property, plant and equipment	420,744	455,822
Investment in subsidiaries (equity method)	-293,312	-217,852
Other Noncurrent Assets	43,533	472,792
Total assets	945,252	1,060,348
Liabilities, Current	2,038,575	124,275
Long-term liabilities	44,548	1,942,043
Stockholders' equity	-1,137,871	-1,005,970
Total liabilities and stockholders' equity	945,252	1,060,348
Restricted Guarantor Subsidiaries [Member]
Current assets	13,909	10,735
Property, plant and equipment	14,357	15,486
Investment in subsidiaries (equity method)	0	0
Other Noncurrent Assets	0	0
Total assets	28,266	26,221
Liabilities, Current	13,837	12,210
Long-term liabilities	15,131	19,242
Stockholders' equity	-702	-5,231
Total liabilities and stockholders' equity	28,266	26,221
Restricted Non-Guarantor Subsidiaries [Member]
Current assets	68,513	53,034
Property, plant and equipment	280,830	307,865
Investment in subsidiaries (equity method)	-82,360	-33,840
Other Noncurrent Assets	18,712	32,892
Total assets	285,695	359,951
Liabilities, Current	520,296	17,167
Long-term liabilities	58,009	542,659
Stockholders' equity	-292,610	-199,875
Total liabilities and stockholders' equity	285,695	359,951
Unrestricted Non-Guarantor Subsidiaries [Member]
Current assets	82	909
Property, plant and equipment	0	0
Investment in subsidiaries (equity method)	-82,379	-33,840
Other Noncurrent Assets	0	0
Total assets	-82,297	-32,931
Liabilities, Current	63	888
Long-term liabilities	0	0
Stockholders' equity	-82,360	-33,819
Total liabilities and stockholders' equity	-82,297	-32,931
Fortune Creek [Member]
Current assets	1,742	1,110
Property, plant and equipment	12,849	81,632
Investment in subsidiaries (equity method)	0	0
Other Noncurrent Assets	0	0
Total assets	14,591	82,742
Liabilities, Current	3,522	1,671
Long-term liabilities	1,492	1,546
Stockholders' equity	9,577	79,525
Total liabilities and stockholders' equity	14,591	82,742
Consolidating Eliminations [Member]
Current assets	-435,256	-21,414
Property, plant and equipment	0	0
Investment in subsidiaries (equity method)	458,051	285,532
Other Noncurrent Assets	0	-390,723
Total assets	22,795	-126,605
Liabilities, Current	-435,256	-21,414
Long-term liabilities	91,956	-264,591
Stockholders' equity	366,095	159,400
Total liabilities and stockholders' equity	$22,795	($126,605)

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, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenue													$569,428	$561,562	$709,038
Operating expenses													483,994	436,246	3,215,896
Equity in net earnings of subsidiaries													0	0	0
Operating income (loss)	18,168	[1]	64,784	13,536	-11,054	13,575	[2]	60,049	[3]	394,894	[4]	-3,874	85,434	464,644	-2,465,761
Fortune Creek accretion													-15,067	-19,245	-19,472
Interest expense and other													-169,867	-269,231	-162,943
Income tax (expense) benefit													-3,600	-14,550	295,570
Net income (loss)													-103,100	161,618	-2,352,606
Net income (loss) attributable to Quicksilver	-31,929		23,757	-36,095	-58,833	-31,775		10,577		242,523		-59,707	-103,100	161,618	-2,352,606
Other comprehensive income (loss)													-38,028	-51,612	-53,365
Equity in OCI of subsidiaries													0	0	0
Comprehensive income (loss)													-141,128	110,006	-2,405,971
Quicksilver Resources Inc. [Member]
Revenue													410,455	416,516	611,477
Operating expenses													299,499	329,975	2,643,690
Equity in net earnings of subsidiaries													-55,678	-9,896	-437,510
Operating income (loss)													55,278	415,973	-2,428,626
Fortune Creek accretion													0	0	0
Interest expense and other													-157,350	-242,279	-152,077
Income tax (expense) benefit													-2,614	-12,076	228,097
Net income (loss)													-104,686	161,618	-2,352,606
Other comprehensive income (loss)													-31,476	-40,166	-57,273
Equity in OCI of subsidiaries													-6,552	-11,446	3,908
Comprehensive income (loss)													-142,714	110,006	-2,405,971
Restricted Guarantor Subsidiaries [Member]
Revenue													5,730	788	4,574
Operating expenses													1,286	346	4,109
Equity in net earnings of subsidiaries													0	0	0
Operating income (loss)													4,444	442	465
Fortune Creek accretion													0	0	0
Interest expense and other													86	0	0
Income tax (expense) benefit													-1,586	0	-163
Net income (loss)													2,944	442	302
Other comprehensive income (loss)													0	0	0
Equity in OCI of subsidiaries													0	0	0
Comprehensive income (loss)													2,944	442	302
Restricted Non-Guarantor Subsidiaries [Member]
Revenue													153,243	144,258	95,887
Operating expenses													134,213	118,481	577,696
Equity in net earnings of subsidiaries													-64,056	-6,682	-12,747
Operating income (loss)													-45,026	19,095	-494,556
Fortune Creek accretion													0	0	0
Interest expense and other													-12,610	-26,959	-10,914
Income tax (expense) benefit													-986	-2,474	67,658
Net income (loss)													-58,622	-10,338	-437,812
Other comprehensive income (loss)													-6,552	-11,446	3,908
Equity in OCI of subsidiaries													0	0	0
Comprehensive income (loss)													-65,174	-21,784	-433,904
Unrestricted Non-Guarantor Subsidiaries [Member]
Revenue													0	0	0
Operating expenses													0	0	0
Equity in net earnings of subsidiaries													-48,989	12,563	6,726
Operating income (loss)													-48,989	12,563	6,726
Fortune Creek accretion													0	0	0
Interest expense and other													0	0	21
Income tax (expense) benefit													0	0	0
Net income (loss)													-48,989	12,563	6,747
Other comprehensive income (loss)													0	0	0
Equity in OCI of subsidiaries													0	0	0
Comprehensive income (loss)													-48,989	12,563	6,747
Fortune Creek [Member]
Revenue													17,585	22,364	14,639
Operating expenses													66,581	9,808	7,940
Equity in net earnings of subsidiaries													0	0	0
Operating income (loss)													-48,996	12,556	6,699
Fortune Creek accretion													0	0	0
Interest expense and other													7	7	27
Income tax (expense) benefit													0	0	0
Net income (loss)													-48,989	12,563	6,726
Other comprehensive income (loss)													0	0	0
Equity in OCI of subsidiaries													0	0	0
Comprehensive income (loss)													-48,989	12,563	6,726
Consolidating Eliminations [Member]
Revenue													-17,585	-22,364	-17,539
Operating expenses													-17,585	-22,364	-17,539
Equity in net earnings of subsidiaries													168,723	4,015	443,531
Operating income (loss)													168,723	4,015	443,531
Fortune Creek accretion													-15,067	-19,245	-19,472
Interest expense and other													0	0	0
Income tax (expense) benefit													1,586	0	-22
Net income (loss)													155,242	-15,230	424,037
Other comprehensive income (loss)													0	0	0
Equity in OCI of subsidiaries													6,552	11,446	-3,908
Comprehensive income (loss)													161,794	-3,784	420,129
Tokyo Gas [Member]
Gain on Tokyo Gas Transaction										333,200			0	339,328	0
Tokyo Gas [Member] | Quicksilver Resources Inc. [Member]
Gain on Tokyo Gas Transaction														339,328
Tokyo Gas [Member] | Restricted Guarantor Subsidiaries [Member]
Gain on Tokyo Gas Transaction														0
Tokyo Gas [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Gain on Tokyo Gas Transaction														0
Tokyo Gas [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Gain on Tokyo Gas Transaction														0
Tokyo Gas [Member] | Fortune Creek [Member]
Gain on Tokyo Gas Transaction														0
Tokyo Gas [Member] | Consolidating Eliminations [Member]
Gain on Tokyo Gas Transaction														0
kwk_CrestwoodLP [Member]
Crestwood earn-out													0	0	41,097
kwk_CrestwoodLP [Member] | Quicksilver Resources Inc. [Member]
Crestwood earn-out															41,097
kwk_CrestwoodLP [Member] | Restricted Guarantor Subsidiaries [Member]
Crestwood earn-out															0
kwk_CrestwoodLP [Member] | Restricted Non-Guarantor Subsidiaries [Member]
Crestwood earn-out															0
kwk_CrestwoodLP [Member] | Unrestricted Non-Guarantor Subsidiaries [Member]
Crestwood earn-out															0
kwk_CrestwoodLP [Member] | Fortune Creek [Member]
Crestwood earn-out															0
kwk_CrestwoodLP [Member] | Consolidating Eliminations [Member]
Crestwood earn-out															$0
[1]	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
[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 $8.0 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.

Condensed_Consolidating_Financ4

Condensed Consolidating Financial Information (Schedule of Condensed Consolidated Statements of Cash Flows) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net cash flow provided (used) by operating activities	($7,629)	($51,700)	$227,727
Purchases of property, plant and equipment	-133,481	-101,288	-485,479
Investment in subsidiary	0
Proceeds from Crestwood earn-out			41,097
Proceeds from sale of properties and equipment	3,222	7,171	72,725
Purchases of marketable securities	-55,890	-213,738	0
Proceeds from Sale and Maturity of Marketable Securities	222,025	47,603
Net cash used by investing activities	131,463	246,044	-371,657
Issuance of debt	243,184	1,237,352	467,959
Repayments of debt	-193,689	-1,308,382	-310,430
Debt issuance costs	-1,705	-26,296	-3,022
Distribution of Fortune Creek Partnership funds	-39,993	-14,965	-14,285
Intercompany Note	0	0
Intercompany financing	0
Contribution received	0
Proceeds from exercise of stock options	0	0	11
Purchase of treasury stock	-2,388	-1,927	-3,144
Net Cash Provided by (Used in) Financing Activities	5,409	-114,218	137,089
Effect of exchange rates on cash	5,183	4,026	-1,354
Net increase (decrease) in cash and equivalents	134,426	84,152	-8,195
Cash and cash equivalents at beginning of period	89,103	4,951	13,146
Cash and cash equivalents at end of period	223,529	89,103	4,951
kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out	0	0	41,097
Tokyo Gas [Member]
Proceeds from Southwestern Transaction	0	463,999	0
Proceeds from Tokyo Gas Transaction	0	463,999	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	463,999	0
Synergy [Member]
Proceeds from Southwestern Transaction	0	42,297	0
Proceeds from Tokyo Gas Transaction	0	42,297	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0	42,297	0
Sandwash Basin [Member]
Proceeds from Southwestern Transaction	95,587	0	0
Proceeds from Tokyo Gas Transaction	95,587	0	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587	0	0
Quicksilver Resources Inc. [Member]
Net cash flow provided (used) by operating activities	-43,824	-82,722	163,353
Purchases of property, plant and equipment	-102,898	-67,263	-231,934
Investment in subsidiary	881
Proceeds from sale of properties and equipment	2,549	7,128	72,362
Purchases of marketable securities	-55,890	-213,738
Proceeds from Sale and Maturity of Marketable Securities	222,025	47,603
Net cash used by investing activities	162,254	280,026	-118,475
Issuance of debt	174,000	1,215,266	228,500
Repayments of debt	-138,651	-1,157,969	-264,018
Debt issuance costs	-1,069	-26,296	-1,972
Distribution of Fortune Creek Partnership funds	0	0	0
Intercompany Note	-22,559	-147,103
Intercompany financing	0
Contribution received	0
Proceeds from exercise of stock options			11
Purchase of treasury stock	-2,388	-1,927	-3,144
Net Cash Provided by (Used in) Financing Activities	9,333	-118,029	-40,623
Effect of exchange rates on cash	0	0	0
Net increase (decrease) in cash and equivalents	127,763	79,275	4,255
Cash and cash equivalents at beginning of period	83,893	4,618	363
Cash and cash equivalents at end of period	211,656	83,893	4,618
Quicksilver Resources Inc. [Member] | kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out			41,097
Quicksilver Resources Inc. [Member] | Tokyo Gas [Member]
Proceeds from Southwestern Transaction		463,999
Proceeds from Tokyo Gas Transaction		463,999
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		463,999
Quicksilver Resources Inc. [Member] | Synergy [Member]
Proceeds from Southwestern Transaction		42,297
Proceeds from Tokyo Gas Transaction		42,297
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		42,297
Quicksilver Resources Inc. [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	95,587
Proceeds from Tokyo Gas Transaction	95,587
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	95,587
Restricted Guarantor Subsidiaries [Member]
Net cash flow provided (used) by operating activities	-1,349	0	656
Purchases of property, plant and equipment	-60	0	-656
Investment in subsidiary	0
Proceeds from sale of properties and equipment	0	0	0
Purchases of marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	-60	0	-656
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	0
Intercompany Note	0	0
Intercompany financing	-1,409
Contribution received	0
Proceeds from exercise of stock options			0
Purchase of treasury stock	0	0	0
Net Cash Provided by (Used in) Financing Activities	1,409	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] | kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out			0
Restricted Guarantor Subsidiaries [Member] | Tokyo Gas [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Restricted Guarantor Subsidiaries [Member] | Synergy [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Restricted Guarantor Subsidiaries [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	0
Proceeds from Tokyo Gas Transaction	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Restricted Non-Guarantor Subsidiaries [Member]
Net cash flow provided (used) by operating activities	31,559	20,591	49,271
Purchases of property, plant and equipment	-30,523	-33,520	-242,158
Investment in subsidiary	-26,395
Proceeds from sale of properties and equipment	673	43	363
Purchases of marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	-56,245	-33,477	-241,795
Issuance of debt	69,184	22,086	239,459
Repayments of debt	-55,038	-150,413	-46,412
Debt issuance costs	-636	0	-1,050
Distribution of Fortune Creek Partnership funds	0	0	0
Intercompany Note	22,559	147,103
Intercompany financing	2,290
Contribution received	0
Proceeds from exercise of stock options			0
Purchase of treasury stock	0	0	0
Net Cash Provided by (Used in) Financing Activities	33,779	18,776	191,997
Effect of exchange rates on cash	-3,046	-1,755	527
Net increase (decrease) in cash and equivalents	6,047	4,135	0
Cash and cash equivalents at beginning of period	4,135	0	0
Cash and cash equivalents at end of period	10,182	4,135	0
Restricted Non-Guarantor Subsidiaries [Member] | kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out			0
Restricted Non-Guarantor Subsidiaries [Member] | Tokyo Gas [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Restricted Non-Guarantor Subsidiaries [Member] | Synergy [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Restricted Non-Guarantor Subsidiaries [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	0
Proceeds from Tokyo Gas Transaction	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Unrestricted Non-Guarantor Subsidiaries [Member]
Net cash flow provided (used) by operating activities	-2	22	0
Purchases of property, plant and equipment	0	0	0
Investment in subsidiary	-26,395
Proceeds from sale of properties and equipment	0	0	0
Purchases of marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	-26,395	0	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	0	0	0
Intercompany Note	0	0
Intercompany financing	0
Contribution received	-26,395
Proceeds from exercise of stock options			0
Purchase of treasury stock	0	0	0
Net Cash Provided by (Used in) Financing Activities	26,395	0	0
Effect of exchange rates on cash	0	0	0
Net increase (decrease) in cash and equivalents	-2	22	0
Cash and cash equivalents at beginning of period	22	0	0
Cash and cash equivalents at end of period	20	22	0
Unrestricted Non-Guarantor Subsidiaries [Member] | kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out			0
Unrestricted Non-Guarantor Subsidiaries [Member] | Tokyo Gas [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Unrestricted Non-Guarantor Subsidiaries [Member] | Synergy [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Unrestricted Non-Guarantor Subsidiaries [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	0
Proceeds from Tokyo Gas Transaction	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Fortune Creek [Member]
Net cash flow provided (used) by operating activities	5,987	10,409	14,447
Purchases of property, plant and equipment	0	-505	-10,731
Investment in subsidiary	0
Proceeds from sale of properties and equipment	0	0	0
Purchases of marketable securities	0	0
Proceeds from Sale and Maturity of Marketable Securities	0	0
Net cash used by investing activities	0	-505	-10,731
Issuance of debt	0	0	0
Repayments of debt	0	0	0
Debt issuance costs	0	0	0
Distribution of Fortune Creek Partnership funds	-39,993	-14,965	-14,285
Intercompany Note	0	0
Intercompany financing	0
Contribution received	-26,395
Proceeds from exercise of stock options			0
Purchase of treasury stock	0	0	0
Net Cash Provided by (Used in) Financing Activities	-13,598	-14,965	-14,285
Effect of exchange rates on cash	8,229	5,781	-1,881
Net increase (decrease) in cash and equivalents	618	720	-12,450
Cash and cash equivalents at beginning of period	1,053	333	12,783
Cash and cash equivalents at end of period	1,671	1,053	333
Fortune Creek [Member] | kwk_CrestwoodLP [Member]
Proceeds from Crestwood earn-out			0
Fortune Creek [Member] | Tokyo Gas [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Fortune Creek [Member] | Synergy [Member]
Proceeds from Southwestern Transaction		0
Proceeds from Tokyo Gas Transaction		0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates		0
Fortune Creek [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	0
Proceeds from Tokyo Gas Transaction	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	0
Consolidation, Eliminations [Member]
Net cash flow provided (used) by operating activities	0
Purchases of property, plant and equipment	0
Investment in subsidiary	51,909
Proceeds from sale of properties and equipment	0
Purchases of marketable securities	0
Proceeds from Sale and Maturity of Marketable Securities	0
Net cash used by investing activities	51,909
Issuance of debt	0
Repayments of debt	0
Debt issuance costs	0
Distribution of Fortune Creek Partnership funds	0
Intercompany Note	0
Intercompany financing	-881
Contribution received	52,790
Purchase of treasury stock	0
Net Cash Provided by (Used in) Financing Activities	-51,909
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
Consolidation, Eliminations [Member] | Sandwash Basin [Member]
Proceeds from Southwestern Transaction	0
Proceeds from Tokyo Gas Transaction	0
Proceeds from Divestiture of Interest in Subsidiaries and Affiliates	$0

Segment_Information_Operating_

Segment Information (Operating Income And Property And Equipment Costs Incurred) (Details) (USD $)	3 Months Ended												12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Number of geographical segments	2												2
Revenue	$196,112		$163,498	$118,032	$91,786	$114,246		$153,116		$175,497		$118,703	$569,428	$561,562	$709,038
Depletion, depreciation and accretion													61,126	62,612	163,624
DD&A															163,624
Impairment expense	71,900												71,988	1,863	2,625,928
Operating income (loss)	18,168	[1]	64,784	13,536	-11,054	13,575	[2]	60,049	[3]	394,894	[4]	-3,874	85,434	464,644	-2,465,761
Property and equipment costs incurred													129,390	98,661	390,456
Property, Plant and Equipment, Net	728,780					860,805							728,780	860,805
Assets	1,214,302					1,369,726							1,214,302	1,369,726
UNITED STATES
Segment Reporting Information [Line Items]
Revenue													410,444	416,462	598,892
Depletion, depreciation and accretion													30,411	37,540
DD&A															123,370
Impairment expense													2,450	1,809	2,152,665
Operating income (loss)													156,382	476,610	-1,921,073
Property and equipment costs incurred													100,592	64,976	189,997
Property, Plant and Equipment, Net	416,901					451,840							416,901	451,840
Assets	881,906					895,388							881,906	895,388
Canada [Member]
Segment Reporting Information [Line Items]
Revenue													150,876	141,870	105,949
Depletion, depreciation and accretion													23,902	17,508
DD&A															32,686
Impairment expense													11,043	0	465,935
Operating income (loss)													22,601	32,648	-474,768
Property and equipment costs incurred													27,585	16,838	174,867
Property, Plant and Equipment, Net	280,830					306,423							280,830	306,423
Assets	285,695					359,951							285,695	359,951
Midstream [Member]
Segment Reporting Information [Line Items]
Revenue													25,693	25,594	21,735
Depletion, depreciation and accretion													4,970	5,249
DD&A															5,182
Impairment expense													58,495	54	7,328
Operating income (loss)													-44,412	13,008	8,163
Property and equipment costs incurred													86	7,055	18,742
Property, Plant and Equipment, Net	27,205					97,118							27,205	97,118
Assets	42,857					108,963							42,857	108,963
Corporate [Member]
Segment Reporting Information [Line Items]
Revenue													0	0	0
Depletion, depreciation and accretion													1,843	2,315
DD&A															2,386
Impairment expense													0	0	0
Operating income (loss)													-49,137	-57,622	-78,083
Property and equipment costs incurred													1,127	9,792	6,850
Property, Plant and Equipment, Net	3,844					5,424							3,844	5,424
Assets	3,844					5,424							3,844	5,424
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue													-17,585	-22,364	-17,538
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 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
[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 $8.0 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.

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Cash Flow Information [Abstract]
Interest, net of capitalized interest	$152,983	$254,901	$154,663
Income taxes	$7,051	($833)	$20,682

Supplemental_Cash_Flow_Informa3

Supplemental Cash Flow Information (Other Significant Noncash Transactions) (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Dividends Payable [Line Items]
Working Capital Related To Capital Expenditures	$4,666	$10,324	$10,939

Employee_Benefits_Details

Employee Benefits (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
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	3,900,000	4,000,000	5,000,000
United States Of America [Member]
Employee Benefits [Line Items]
Expenses associated with company contributions	1,600,000	1,800,000	2,300,000
Canada [Member]
Employee Benefits [Line Items]
Expenses associated with company contributions	$600,000	$700,000	$700,000

Transactions_With_Related_Part1

Transactions With Related Parties (Details) (USD $)	12 Months Ended			1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	31-May-13
Related Party Transaction [Line Items]
Percentage of ownership interest	100.00%
Darden Family [Member]
Related Party Transaction [Line Items]
Percentage of ownership interest	25.00%
Mercury Exploration Company [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Revenues from Transactions with Related Party	$100,000	$100,000	$100,000
Thomas F. Darden [Member]
Related Party Transaction [Line Items]
Consulting fee payments	540,000
Monthly Business Expense Allowance					12,500
Cash Bonus Related to Tokyo Gas Transaction					1,100,000
Stock Granted, Value, Share-based Compensation, Gross				191,100	1,100,000
Legal Fee Reimbursement Allowance					40,000
Monthly Consulting Fee					45,000
Maximum Bonus Eligibility					2,500,000
Office allowance payments	150,000
COBRA payments	39,000
Cash bonus				286,650
Rent On Buildings [Member] | Darden Family [Member]
Related Party Transaction [Line Items]
Payments to related parties			100,000
Commissions Paid [Member] | Darden Family [Member]
Related Party Transaction [Line Items]
Payments to related parties		200,000
Use Of Airplane [Member] | Darden Family [Member]
Related Party Transaction [Line Items]
Payments to related parties		$300,000	$500,000
Restricted Stock [Member] | Thomas F. Darden [Member]
Related Party Transaction [Line Items]
Unvested Equity Awards					242,724
Vested equity awards				72,662
Employee Stock Option [Member] | Thomas F. Darden [Member]
Related Party Transaction [Line Items]
Unvested Equity Awards					304,407

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
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction						5.9		8.2
Operating revenue	$196,112		$163,498	$118,032	$91,786	$114,246		$153,116		$175,497		$118,703	$569,428	$561,562	$709,038
Operating Income (Loss)	18,168	[1]	64,784	13,536	-11,054	13,575	[2]	60,049	[3]	394,894	[4]	-3,874	85,434	464,644	-2,465,761
Net income	-31,929		23,757	-36,095	-58,833	-31,775		10,577		242,523		-59,707	-103,100	161,618	-2,352,606
Basic net earnings per share	($0.18)		$0.13	($0.21)	($0.34)	($0.18)		$0.06		$1.37		($0.35)	($0.59)	$0.92	($13.83)
Diluted net earnings per share	($0.18)		$0.13	($0.21)	($0.34)	($0.18)		$0.06		$1.37		($0.35)	($0.59)	$0.92	($13.83)
Impairment expense	71,900												71,988	1,863	2,625,928
Tokyo Gas [Member]
Schedule Of Quarterly Financial Data [Line Items]
Gain on Tokyo Gas Transaction										$333,200			$0	$339,328	$0
compensation expense correction [Domain]
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction										3.6		1.2		2.4	2.4
adjustment to Tokyo Gas Transaction [Member]
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction						1.7		8
expense to settle litigation correction [Member]
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction						3
amortization of deferred financing costs correction [Member]
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction						0.8
strategic transaction fees correction [Member]
Schedule Of Quarterly Financial Data [Line Items]
Immaterial Error Correction						0.5
[1]	Operating income for the fourth quarter of 2014 includes a non-cash property impairment loss of $71.9 million, primarily due to our Fortune Creek gathering system impairment.
[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 $8.0 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.

Supplemental_Oil_and_Gas_Infor1

Supplemental Oil and Gas Information (Unaudited) Reserve Rollforward (Details)	12 Months Ended
	Dec. 31, 2014																												Dec. 31, 2013		Dec. 31, 2012
	MMcf																												MMcf		MMcf
Reserve Quantities [Line Items]
Oil and Gas Exploration and Production Industries Disclosures [Text Block]	SUPPLEMENTAL OIL AND GAS INFORMATION (UNAUDITED)
	Proved oil and natural 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 2014, 2013 and 2012 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, 2014 were as follows:
		Natural Gas (MMcf)									NGL (MBbl)						Oil (MBbl)					Total (MMcfe)
		U.S.			Canada			Total			U.S.		Canada		Total		U.S.		Canada	Total		U.S.		Canada		Total
	December 31, 2011	1,828,904			330,631			2,159,535			102,145		11		102,156		3,035		—	3,035		2,459,984		330,697		2,790,681
	Revisions (3)	(910,386	)		(33,945	)		(944,331	)		(45,379	)	1		(45,378	)	(479	)	—	(479	)	(1,185,534	)	(33,939	)	(1,219,473	)
	Extensions and discoveries (2)	25,858			9			25,867			3,518		—		3,518		345		—	345		49,036		9		49,045
	Sales in place (1)	(20,616	)		—			(20,616	)		(42	)	—		(42	)	(85	)	—	(85	)	(21,378	)	—		(21,378	)
	Production	(75,712	)		(29,912	)		(105,624	)		(4,069	)	(2	)	(4,071	)	(287	)	—	(287	)	(101,848	)	(29,924	)	(131,772	)
	31-Dec-12	848,048			266,783			1,114,831			56,173		10		56,183		2,529		—	2,529		1,200,260		266,843		1,467,103
	Revisions (3)	234,835			28,948			263,783			750		—		750		62		—	62		239,707		28,948		268,655
	Extensions and discoveries (2)	50,992			9,697			60,689			—		—		—		—		—	—		50,992		9,697		60,689
	Sales in place (4)	(257,741	)		—			(257,741	)		(14,333	)	—		(14,333	)	(2,207	)	—	(2,207	)	(356,981	)	—		(356,981	)
	Production	(51,684	)		(39,372	)		(91,056	)		(2,856	)	(1	)	(2,857	)	(185	)	—	(185	)	(69,930	)	(39,378	)	(109,308	)
	31-Dec-13	824,450			266,056			1,090,506			39,734		9		39,743		199		—	199		1,064,048		266,110		1,330,158
	Revisions (3)	(148,359	)		42,941			(105,418	)		(3,675	)	3		(3,672	)	(14	)	—	(14	)	(170,493	)	42,959		(127,534	)
	Extensions and discoveries (2)	413			—			413			—		—		—		188		—	188		1,541		—		1,541
	Sales in place	—			—			—			—		—		—		(5	)	—	(5	)	(30	)	—		(30	)
	Production	(46,027	)		(31,169	)		(77,196	)		(2,105	)	(2	)	(2,107	)	(81	)	—	(81	)	(59,143	)	(31,181	)	(90,324	)
	31-Dec-14	630,477			277,828			908,305			33,954		10		33,964		287		—	287		835,923		277,888		1,113,811
	Proved developed reserves
	31-Dec-12	725,361			266,783			992,144			47,284		10		47,294		2,416		—	2,416		1,023,561		266,843		1,290,404
	31-Dec-13	702,147			260,159			962,306			34,603		9		34,612		139		—	139		910,599		260,213		1,170,812
	31-Dec-14	619,751			277,828			897,579			33,954		11		33,965		287		—	287		825,197		277,894		1,103,091
	Proved undeveloped reserves
	31-Dec-12	122,687			—			122,687			8,890		—		8,890		113		—	113		176,705		—		176,705
	31-Dec-13	122,303			5,896			128,199			5,131		—		5,131		60		—	60		153,449		5,896		159,345
	31-Dec-14	10,726			—			10,726			—		—		—		—		—	—		10,726		—		10,726
	(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:
	•	2014 are attributable to our West Texas Asset as we drilled in areas not previously explored;
	•	2013 are attributable to our Barnett Shale Asset; and
	•	2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed).
	Canadian extensions and discoveries for 2013 and 2012 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 49,712 MMcfe, 419,972 MMcfe and (590,064) MMcfe in 2014, 2013 and 2012, respectively, and changes in non-economic factors of (177,246) MMcfe, (151,615) MMcfe and (629,407) MMcfe in 2014, 2013 and 2012, respectively, including:
	•	In 2014, we removed proved reserves of (143) Bcfe that we were unable to develop due to constrained liquidity
	•	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: (34) Bcfe, (74) Bcfe and (291) Bcfe in 2014, 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 natural gas assets as of December 31, 2014, 2013 and 2012 were as follows:
		U.S.				Canada				Consolidated
		(in thousands)
	2014
	Proved properties	$	4,650,428			$	1,170,739			$	5,821,167
	Unevaluated properties	18,803				—				18,803
	Accumulated DD&A	(4,296,953		)		(928,349		)		(5,225,302		)
	Net capitalized costs	$	372,278			$	242,390			$	614,668
	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
	Our consolidated capital costs incurred for acquisition, exploration and development activities during each of the three years in the period ended December 31, 2014, were as follows:
		U.S.				Canada				Consolidated
		(in thousands)
	2014
Proved acreage	$	—			$	—			$	—
Unproved acreage	21,722				5,519				27,241
Development costs	78,894				22,065				100,959
Exploration costs	63				—				63
Total	$	100,679			$	27,584			$	128,263
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
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, 2014, are set forth below:
	U.S.				Canada				Consolidated
	(in thousands)
2014
Natural gas, NGL and oil revenue	$	292,388			$	132,766			$	425,154
Operating expense	146,383				84,219				230,602
Depletion expense	28,567				11,778				40,345
	117,438				36,769				154,207
Income tax expense	41,103				9,266				50,369
Results from producing activities	$	76,335			$	27,503			$	103,838
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	)
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 oil and natural gas properties. An estimate of such value should consider, among other factors, anticipated future prices of oil and natural gas, 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 2014 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,
	2014				2013				2012
Natural gas – Henry Hub, per MMBtu	$	4.35			$	3.67			$	2.76
Natural gas – AECO, per MMBtu	4.22				2.9				2.35
Oil – WTI Cushing, per Bbl	94.99				97.18				94.71
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, including future abandonment 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 oil and natural gas 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, 2014, 2013 and 2012 was as follows:
	U.S.				Canada				Total
					(in thousands)
31-Dec-14
Future revenue	$	3,476,515			$	1,053,509			$	4,530,024
Future production costs	(1,785,208		)		(483,380		)		(2,268,588		)
Future development costs	(71,143		)		(65,703		)		(136,846		)
Future income taxes	(113,119		)		(11,017		)		(124,136		)
Future net cash flows	1,507,045				493,409				2,000,454
10% discount	(817,744		)		(194,640		)		(1,012,384		)
Standardized measure of discounted future cash flows relating to proved reserves	$	689,301			$	298,769			$	988,070
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
The standardized measure was calculated without giving consideration to any tax valuation allowance.
The primary changes in the Standardized Measure for 2014, 2013 and 2012 were as follows:
	Years Ended December 31,
	2014				2013				2012
					(in thousands)
Sales of oil and natural gas net of production costs	$	(164,436	)		$	(147,402	)		$	(149,326	)
Net changes in economic factors	304,602				326,698				(1,362,793		)
Extensions and discoveries	1,455				43,328				27,003
Development costs incurred	60,169				2,302				172,563
Changes in estimated future development costs	91,635				20,766				620,127
Purchase and sale of reserves, net	(24		)		(237,409		)		(20,529		)
Revision of estimates	(103,478		)		121,916				(1,219,609		)
Accretion of discount	75,925				50,821				196,315
Net change in income taxes	(73,637		)		(86,667		)		560,485
Change in timing and other differences	(27,189		)		13,575				156,031
Net increase (decrease)	$	165,022			$	107,928			$	(1,019,733	)
Revisions, Removal of Proved Undeveloped Reserves not Developed	143																												76		250
Percentage of ownership interest	100.00%
Revisions, Changes in Performance	34																												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	824,450																												848,048		1,828,904
Revisions	-148,359																											[1]	234,835	[1]	-910,386	[1]
Extensions and discoveries	413																											[2]	50,992	[2]	25,858	[2]
Sales in place	0																												-257,741	[3]	-20,616	[4]
Production	-46,027																												-51,684		-75,712
Proved Reserves, End of Period	630,477																												824,450		848,048
Proved Developed Reserves (Volume)	619,751																												702,147		725,361
Proved Undeveloped Reserve (Volume)	10,726																												122,303		122,687
U.S. [Member] | NGL [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	39,734																												56,173		102,145
Revisions	-3,675																											[1]	750	[1]	-45,379	[1]
Extensions and discoveries	0																											[2]	0	[2]	3,518	[2]
Sales in place	0																												-14,333	[3]	-42	[4]
Production	-2,105																												-2,856		-4,069
Proved Reserves, End of Period	33,954																												39,734		56,173
Proved Developed Reserves (Volume)	33,954																												34,603		47,284
Proved Undeveloped Reserve (Volume)	0																												5,131		8,890
U.S. [Member] | Oil [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	199																												2,529		3,035
Revisions	-14																											[1]	62	[1]	-479	[1]
Extensions and discoveries	188																											[2]	0	[2]	345	[2]
Sales in place	-5																												-2,207	[3]	-85	[4]
Production	-81																												-185		-287
Proved Reserves, End of Period	287																												199		2,529
Proved Developed Reserves (Volume)	287																												139		2,416
Proved Undeveloped Reserve (Volume)	0																												60		113
U.S. [Member] | natural gas equivalent [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	1,064,048																												1,200,260		2,459,984
Revisions	-170,493																											[1]	239,707	[1]	-1,185,534	[1]
Extensions and discoveries	1,541																											[2]	50,992	[2]	49,036	[2]
Sales in place	-30																												-356,981	[3]	-21,378	[4]
Production	-59,143																												-69,930		-101,848
Proved Reserves, End of Period	835,923																												1,064,048		1,200,260
Proved Developed Reserves (Volume)	825,197																												910,599		1,023,561
Proved Undeveloped Reserve (Volume)	10,726																												153,449		176,705
Canada [Member] | Natural Gas [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	266,056																												266,783		330,631
Revisions	42,941																											[1]	28,948	[1]	-33,945	[1]
Extensions and discoveries	0																											[2]	9,697	[2]	9	[2]
Sales in place	0																												0	[3]	0	[4]
Production	-31,169																												-39,372		-29,912
Proved Reserves, End of Period	277,828																												266,056		266,783
Proved Developed Reserves (Volume)	277,828																												260,159		266,783
Proved Undeveloped Reserve (Volume)	0																												5,896		0
Canada [Member] | NGL [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	9																												10		11
Revisions	3																											[1]	0	[1]	1	[1]
Extensions and discoveries	0																											[2]	0	[2]	0	[2]
Sales in place	0																												0	[3]	0	[4]
Production	-2																												-1		-2
Proved Reserves, End of Period	10																												9		10
Proved Developed Reserves (Volume)	11																												9		10
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																												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
Canada [Member] | natural gas equivalent [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	266,110																												266,843		330,697
Revisions	42,959																											[1]	28,948	[1]	-33,939	[1]
Extensions and discoveries	0																											[2]	9,697	[2]	9	[2]
Sales in place	0																												0	[3]	0	[4]
Production	-31,181																												-39,378		-29,924
Proved Reserves, End of Period	277,888																												266,110		266,843
Proved Developed Reserves (Volume)	277,894																												260,213		266,843
Proved Undeveloped Reserve (Volume)	0																												5,896		0
Consolidated [Member] | Natural Gas [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	1,090,506																												1,114,831		2,159,535
Revisions	-105,418																											[1]	263,783	[1]	-944,331	[1]
Extensions and discoveries	413																											[2]	60,689	[2]	25,867	[2]
Sales in place	0																												-257,741	[3]	-20,616	[4]
Production	-77,196																												-91,056		-105,624
Proved Reserves, End of Period	908,305																												1,090,506		1,114,831
Proved Developed Reserves (Volume)	897,579																												962,306		992,144
Proved Undeveloped Reserve (Volume)	10,726																												128,199		122,687
Consolidated [Member] | NGL [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	39,743																												56,183		102,156
Revisions	-3,672																											[1]	750	[1]	-45,378	[1]
Extensions and discoveries	0																											[2]	0	[2]	3,518	[2]
Sales in place	0																												-14,333	[3]	-42	[4]
Production	-2,107																												-2,857		-4,071
Proved Reserves, End of Period	33,964																												39,743		56,183
Proved Developed Reserves (Volume)	33,965																												34,612		47,294
Proved Undeveloped Reserve (Volume)	0																												5,131		8,890
Consolidated [Member] | Oil [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	199																												2,529		3,035
Revisions	-14																											[1]	62	[1]	-479	[1]
Extensions and discoveries	188																											[2]	0	[2]	345	[2]
Sales in place	-5																												-2,207	[3]	-85	[4]
Production	-81																												-185		-287
Proved Reserves, End of Period	287																												199		2,529
Proved Developed Reserves (Volume)	287																												139		2,416
Proved Undeveloped Reserve (Volume)	0																												60		113
Consolidated [Member] | natural gas equivalent [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Proved Reserves, Beginning of Period	1,330,158																												1,467,103		2,790,681
Revisions	-127,534																											[1]	268,655	[1]	-1,219,473	[1]
Extensions and discoveries	1,541																											[2]	60,689	[2]	49,045	[2]
Sales in place	-30																												-356,981	[3]	-21,378	[4]
Production	-90,324																												-109,308		-131,772
Proved Reserves, End of Period	1,113,811																												1,330,158		1,467,103
Proved Developed Reserves (Volume)	1,103,091																												1,170,812		1,290,404
Proved Undeveloped Reserve (Volume)	10,726																												159,345		176,705
Changes in Non-Economic Factors [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Revisions	-177,246																												-151,615		-629,407
Changes in Economic Factors [Member]
Change in Proved Developed and Undeveloped Reserves [Roll Forward]
Revisions	49,712																												419,972		-590,064
Barnett Shale [Member] | U.S. [Member]
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserves, Extensions, Discoveries, and Additions, Percent																															96.00%
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 49,712B MMcfe, 419,972 MMcfe and (590,064) MMcfe in 2014, 2013 and 2012, respectively, and changes in non-economic factors of (177,246)B MMcfe, (151,615)B MMcfe and (629,407) MMcfe in 2014, 2013 and 2012, respectively, including:b"In 2014, we removed proved reserves of (143) Bcfe that we were unable to develop due to constrained liquidityb"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: (34) Bcfe, (74) Bcfe and (291) Bcfe in 2014, 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"2014 are attributable to our West Texas Asset as we drilled in areas not previously explored;b"2013 are attributable to our Barnett Shale Asset; andb"2012 are 96% attributable to our Barnett Shale Asset, 4% to our Niobrara and West Texas Assets (of which 13% were proved developed).Canadian extensions and discoveries for 2013 and 2012 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_Infor2

Supplemental Oil and Gas Information (Unaudited) Net Carrying Value of Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Accumulated DD&A	($5,225,302)	($5,268,719)
Net oil and gas properties	614,668	640,443
U.S. [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	4,650,428	4,645,777	4,681,860
Unevaluated properties	18,803	19,343	90,035
Accumulated DD&A	-4,296,953	-4,268,387	-4,233,391
Net oil and gas properties	372,278	396,733	538,504
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	1,170,739	1,041,780	1,089,053
Unevaluated properties	0	202,262	217,232
Accumulated DD&A	-928,349	-1,000,332	-1,063,829
Net oil and gas properties	242,390	243,710	242,456
Consolidated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Proved properties	5,821,167	5,687,557	5,770,913
Unevaluated properties	18,803	221,605	307,267
Accumulated DD&A	-5,225,302	-5,268,719	-5,297,220
Net oil and gas properties	$614,668	$640,443	$780,960

Supplemental_Oil_and_Gas_Infor3

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, 2014	Dec. 31, 2013	Dec. 31, 2012
U.S. [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved acreage	$0	$0	$0
Unproved acreage	21,722	15,843	23,711
Development costs	78,894	49,299	131,926
Exploration costs	63	0	35,244
Total	100,679	65,142	190,881
Canada [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved acreage	0	0	0
Unproved acreage	5,519	6,305	5,612
Development costs	22,065	17,422	178,808
Exploration costs	0	0	8,304
Total	27,584	23,727	192,724
Consolidated [Member]
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities [Line Items]
Proved acreage	0	0	0
Unproved acreage	27,241	22,148	29,323
Development costs	100,959	66,721	310,734
Exploration costs	63	0	43,548
Total	$128,263	$88,869	$383,605

Supplemental_Oil_and_Gas_Infor4

Supplemental Oil and Gas Information (Unaudited) Results from Producing Activities (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Income (loss) before income taxes	($99,500)	$176,168	($2,648,176)
U.S. [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and oil revenue	292,388	331,964	538,902
Operating expense	146,383	167,425	226,542
Depletion expense	28,567	34,995	116,005
Impairment expense			2,152,128
Income (loss) before income taxes	117,438	129,544	-1,955,773
Income tax expense (benefit)	41,103	45,340	-684,521
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs)	76,335	84,204	-1,271,252
Canada [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and oil revenue	132,766	131,527	92,045
Operating expense	84,219	80,475	60,501
Depletion expense	11,778	5,362	24,897
Impairment expense			465,935
Income (loss) before income taxes	36,769	45,690	-459,288
Income tax expense (benefit)	9,266	11,514	-114,822
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs)	27,503	34,176	-344,466
Consolidated [Member]
Capitalized Costs Relating to Oil and Gas Producing Activities, by Geographic Area [Line Items]
Natural gas, NGL and oil revenue	425,154	463,491	630,947
Operating expense	230,602	247,900	287,043
Depletion expense	40,345	40,357	140,902
Impairment expense			2,618,063
Income (loss) before income taxes	154,207	175,234	-2,415,061
Income tax expense (benefit)	50,369	56,854	-799,343
Results of Operations, Oil and Gas Producing Activities Net Income (Excluding Corporate Overhead and Interest Costs)	$103,838	$118,380	($1,615,718)

Supplemental_Oil_and_Gas_Infor5

Supplemental Oil and Gas Information (Unaudited) Prices used for Standardized Measure (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural Gas [Member] | Henry Hub [Member]
Supplemental Oil and Gas Information [Line Items]
Representative prices	4.35	3.67	2.76
Natural Gas [Member] | AECO [Member]
Supplemental Oil and Gas Information [Line Items]
Representative prices	4.22	2.9	2.35
Oil [Member] | WTI Cushing [Member]
Supplemental Oil and Gas Information [Line Items]
Representative prices	94.99	97.18	94.71

Supplemental_Oil_and_Gas_Infor6

Supplemental Oil and Gas Information (Unaudited) Discounted Future Cash Flows of Proved Reserves (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
U.S. [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future revenue	$3,476,515	$3,825,944	$3,980,643
Future production costs	-1,785,208	-2,022,977	-2,552,863
Future development costs	-71,143	-212,280	-239,532
Future income taxes	-113,119	-134,418	81,847
Future net cash flows	1,507,045	1,456,269	1,270,095
10% discount	-817,744	-801,116	-667,738
Standardized measure of discounted future cash flows relating to proved reserves	689,301	655,153	602,357
Canada [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future revenue	1,053,509	656,984	472,539
Future production costs	-483,380	-385,776	-324,424
Future development costs	-65,703	-79,525	-56,354
Future income taxes	-11,017	59,294	80,206
Future net cash flows	493,409	250,977	171,967
10% discount	-194,640	-83,082	-59,204
Standardized measure of discounted future cash flows relating to proved reserves	298,769	167,895	112,763
Consolidated [Member]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Line Items]
Future revenue	4,530,024	4,482,928	4,453,182
Future production costs	-2,268,588	-2,408,753	-2,877,287
Future development costs	-136,846	-291,805	-295,886
Future income taxes	-124,136	-75,124	162,053
Future net cash flows	2,000,454	1,707,246	1,442,062
10% discount	-1,012,384	-884,198	-726,942
Standardized measure of discounted future cash flows relating to proved reserves	$988,070	$823,048	$715,120

Supplemental_Oil_and_Gas_Infor7

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, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Annual Discount Rate for Estimated Timing of Cash Flows	10.00%
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Sales of oil and natural gas net of production costs	($164,436)	($147,402)	($149,326)
Net changes in economic factors	304,602	326,698	-1,362,793
Extensions and discoveries	1,455	43,328	27,003
Development costs incurred	60,169	2,302	172,563
Changes in estimated future development costs	91,635	20,766	620,127
Purchase and sale of reserves, net	-24	-237,409	-20,529
Revision of estimates	-103,478	121,916	-1,219,609
Accretion of discount	75,925	50,821	196,315
Net change in income taxes	-73,637	-86,667	560,485
Change in timing and other differences	-27,189	13,575	156,031
Net increase (decrease)	$165,022	$107,928	($1,019,733)

Supplemental_Oil_and_Gas_Infor8

Supplemental Oil and Gas Information (Unaudited) Narrative (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMcf	MMcf	MMcf
Reserve Quantities [Line Items]
Proved undeveloped reserves that had not been developed, Period	5 years
Removal of proved undeveloped reserves not developed	143	76	250
Changes in performance	34	74	291
Revision of type curve of non producing wells			88
Capital expenditures	$133,481	$101,288	$485,479
Changes in Economic Factors [Member]
Reserve Quantities [Line Items]
Revisions	49,712	419,972	-590,064
Changes in Non-Economic Factors [Member]
Reserve Quantities [Line Items]
Revisions	-177,246	-151,615	-629,407