Continental Resources Inc (CLR) 10-K 24 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 17, 2015	Jun. 30, 2014
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	FALSE
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	CLR
Entity Registrant Name	CONTINENTAL RESOURCES, INC
Entity Central Index Key	732834
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		371,906,845
Entity Public Float			$9.10

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Current assets:
Cash and cash equivalents	$24,381	$28,482
Receivables:
Crude oil and natural gas sales	552,476	643,498
Affiliated parties	13,360	13,107
Joint interest and other, net	567,476	349,579
Derivative assets	52,423	3,616
Inventories	102,179	54,440
Deferred and prepaid taxes	63,266	44,337
Prepaid expenses and other	14,040	10,207
Total current assets	1,389,601	1,147,266
Net property and equipment, based on successful efforts method of accounting	13,635,852	10,721,272
Net debt issuance costs and other	87,625	72,644
Noncurrent derivative assets	31,992	0
Total assets	15,145,070	11,941,182
Current liabilities:
Accounts payable trade	1,263,724	885,289
Revenues and royalties payable	272,755	291,772
Payables to affiliated parties	7,305	5,436
Accrued liabilities and other	404,506	198,113
Derivative liabilities	1,645	90,535
Current portion of long-term debt	2,078	2,011
Total current liabilities	1,952,013	1,473,156
Long-term debt, net of current portion	5,995,837	4,713,821
Other noncurrent liabilities:
Deferred income tax liabilities	2,141,447	1,736,812
Asset retirement obligations, net of current portion	75,462	54,353
Noncurrent derivative liabilities	3,109	7,829
Other noncurrent liabilities	9,358	2,093
Total other noncurrent liabilities	2,229,376	1,801,087
Commitments and contingencies (Note 10)
Shareholders’ equity:
Preferred stock, $0.01 par value; 25,000,000 shares authorized; no shares issued and outstanding	0	0
Common stock, $0.01 par value; 500,000,000 shares authorized; 372,005,502 shares issued and outstanding at December 31, 2014; 371,317,318 shares issued and outstanding at December 31, 2013	3,720	3,713
Additional paid-in capital	1,287,941	1,250,178
Accumulated Other Comprehensive Income (Loss), Net of Tax	-385	0
Retained earnings	3,676,568	2,699,227
Total shareholders’ equity	4,967,844	3,953,118
Total liabilities and shareholders’ equity	$15,145,070	$11,941,182

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Preferred stock, par value	$0.01	$0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common Stock, Par or Stated Value Per Share	$0.01	$0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	372,005,502	371,317,318
Common stock, outstanding	372,005,502	371,317,318

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues:
Crude oil and natural gas sales	$4,107,894	$3,473,026	$2,290,608
Crude oil and natural gas sales to affiliates	95,128	100,405	58,892
Gain (loss) on derivative instruments, net	559,759	-191,751	154,016
Crude oil and natural gas service operations	38,837	40,127	39,071
Total revenues	4,801,618	3,421,807	2,542,587
Operating costs and expenses:
Production expenses	347,349	280,789	193,466
Production and other expenses to affiliates	5,123	1,408	1,974
Production taxes and other expenses	349,760	298,787	198,505
Exploration expenses	50,067	34,947	23,507
Crude oil and natural gas service operations	21,871	29,665	32,248
Depreciation, depletion, amortization and accretion	1,358,669	965,645	692,118
Property impairments	616,888	220,508	122,274
General and administrative expenses	184,655	144,379	121,735
Gain on sale of assets, net	-600	-88	-136,047
Total operating costs and expenses	2,933,782	1,976,040	1,249,780
Income from operations	1,867,836	1,445,767	1,292,807
Other income (expense):
Interest expense	-283,928	-235,275	-140,708
Loss on extinguishment of debt	-24,517	0	0
Other	2,647	2,557	3,097
Total other income (expense)	-305,798	-232,718	-137,611
Income before income taxes	1,562,038	1,213,049	1,155,196
Provision for income taxes	584,697	448,830	415,811
Net income	977,341	764,219	739,385
Basic net income per share (in dollars per share)	$2.65	$2.08	$2.04
Diluted net income per share (in dollars per share)	$2.64	$2.07	$2.03
Foreign currency translation adjustments	-385	0	0
Other Comprehensive Income (Loss), Net of Tax	-385	0	0
Comprehensive Income (Loss), Net of Tax	$976,956	$764,219	$739,385

Consolidated_Statements_of_Sha

Consolidated Statements of Shareholders' Equity (USD $)	Total	Common stock	Additional paid-in capital	Accumulated Other Comprehensive Income (Loss)	Retained earnings
In Thousands, except Share data, unless otherwise specified
Balance at Dec. 31, 2011	$2,308,125	$3,617	$1,108,885		$1,195,623
Balance, shares at Dec. 31, 2011		361,743,376
Net income	739,385				739,385
Other Comprehensive Income (Loss), Net of Tax	0
Public offering of common stock	81,528	78	81,450
Public offering of common stock, shares		7,832,314
Stock-based compensation	30,202		30,202
Excess tax benefit on stock-based compensation	15,618
Stock options:
Exercised	60	2	58
Exercised, shares	173,000	173,000
Repurchased and canceled	-2,951	0	-2,951
Repurchased and canceled, shares		-65,968
Restricted stock:
Issued	18	18	0
Issued, shares		1,832,056
Repurchased and canceled	-8,285	-2	-8,283
Repurchased and canceled, shares		-225,042
Forfeited	-1	-1
Forfeited, shares		-80,374
Balance at Dec. 31, 2012	3,163,699	3,712	1,224,979		1,935,008
Balance, shares at Dec. 31, 2012		371,209,362
Net income	764,219				764,219
Other Comprehensive Income (Loss), Net of Tax	0
Stock-based compensation	39,886		39,886
Stock options:
Repurchased and canceled			0
Restricted stock:
Issued	5	5	0
Issued, shares		522,518
Repurchased and canceled	-14,690	-3	-14,687
Repurchased and canceled, shares		-277,050
Forfeited	-1	-1
Forfeited, shares		-137,512
Balance at Dec. 31, 2013	3,953,118	3,713	1,250,178		2,699,227
Balance, shares at Dec. 31, 2013	371,317,318	371,317,318
Net income	977,341				977,341
Other Comprehensive Income (Loss), Net of Tax	-385			-385
Stock-based compensation	54,343		54,343
Restricted stock:
Issued	14	14	0
Issued, shares		1,424,764
Repurchased and canceled	-16,583	-3	-16,580
Repurchased and canceled, shares		-283,434
Forfeited	-4	-4
Forfeited, shares		-453,146
Balance at Dec. 31, 2014	$4,967,844	$3,720	$1,287,941	($385)	$3,676,568
Balance, shares at Dec. 31, 2014	372,005,502	372,005,502

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
Cash flows from operating activities:
Net income	$977,341	$764,219	$739,385
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,368,311	965,437	694,698
Property impairments	616,888	220,508	122,274
Non-cash (gain) loss on derivatives, net	-174,409	130,196	-199,737
Stock-based compensation	54,353	39,890	29,057
Provision for deferred income taxes	584,677	442,621	405,294
Excess tax benefit from stock-based compensation	0	0	-15,618
Dry hole costs	23,679	9,350	767
Gain on sale of assets, net	-600	-88	-136,047
Loss on extinguishment of debt	24,517	0	0
Other, net	7,637	2,037	5,007
Changes in assets and liabilities:
Accounts receivable	-129,634	-166,138	-91,791
Inventories	-65,919	-7,697	-7,165
Prepaid expenses and other	-57,489	-11,537	14,381
Accounts payable trade	85,540	107,250	-8,487
Revenues and royalties payable	-18,022	28,401	40,030
Accrued liabilities and other	58,880	44,260	40,309
Other noncurrent assets and liabilities	-35	-5,414	-292
Net cash provided by operating activities	3,355,715	2,563,295	1,632,065
Cash flows from investing activities:
Exploration and development	-4,604,468	-3,660,773	-3,493,652
Purchase of producing crude oil and natural gas properties	-48,917	-16,604	-570,985
Purchase of other property and equipment	-63,402	-62,054	-53,468
Proceeds from sale of assets and other	129,388	28,420	214,735
Net cash used in investing activities	-4,587,399	-3,711,011	-3,903,370
Cash flows from financing activities:
Credit facility borrowings	1,695,000	970,000	2,119,000
Repayment of credit facility	-1,805,000	-1,290,000	-1,882,000
Proceeds from issuance of Senior Notes	1,681,834	1,479,375	1,999,000
Redemption of Senior Notes	-300,000	0	0
Premium on redemption of Senior Notes	-17,497	0	0
Proceeds from other debt	0	0	22,000
Repayment of other debt	-2,013	-1,951	-1,579
Debt issuance costs	-8,026	-2,265	-7,373
Repurchase of equity grants	-16,583	-14,690	-11,236
Excess tax benefit from stock-based compensation	0	0	15,618
Exercise of stock options	0	0	60
Net cash provided by financing activities	1,227,715	1,140,469	2,253,490
Effect of exchange rate on cash and cash equivalents	-132
Net change in cash and cash equivalents	-4,101	-7,247	-17,815
Cash and cash equivalents at beginning of period	28,482	35,729	53,544
Cash and cash equivalents at end of period	$24,381	$28,482	$35,729

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization and Summary of Significant Accounting Policies	Organization and Summary of Significant Accounting Policies
	Description of the Company
	Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.
	The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 74% of the Company’s crude oil and natural gas production and approximately 83% of its crude oil and natural gas revenues for the year ended December 31, 2014. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2014, approximately 69% of the Company’s estimated proved reserves were located in the North region. In 2012 and 2013, the Company significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 26% of the Company's crude oil and natural gas production and 31% of its estimated proved reserves as of December 31, 2014.
	The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 64% of the Company's estimated proved reserves as of December 31, 2014.
	Basis of presentation of consolidated financial statements
	The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.
	Stock split
	On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split.
	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements.
	Revenue recognition
	Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2014 and 2013 were not material.
	Cash and cash equivalents
	The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2014, the Company had cash deposits in excess of federally insured amounts of approximately $22.6 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
	Accounts receivable
	The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material.
	Concentration of credit risk
	The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2014, sales to the Company’s two largest purchasers accounted for approximately 14% and 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2014. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in the Company’s operating regions.
	Inventories
	Inventories are stated at the lower of cost or market and consist of the following:
			December 31,
	In thousands		2014				2013
	Tubular goods and equipment		$	15,659			$	11,139
	Crude oil		86,520				43,301
	Total		$	102,179			$	54,440
	Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes:
			December 31,
	MBbls		2014			2013
	Crude oil line fill and tank requirements		1,323			370
	Temporarily stored crude oil		596			344
	Total		1,919			714
	An increase in crude oil line fill requirements associated with new pipelines put into service during 2014 along with initial tank fill at new storage facilities resulted in an increase in crude oil stored in inventory at December 31, 2014 compared to December 31, 2013.
	Crude oil and natural gas properties
	The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.
	Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.
	Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations.
	Service property and equipment
	Service property and equipment consist primarily of furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
	Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:
	Service property and equipment	Useful Lives
		In Years
	Furniture and fixtures	10
	Automobiles	6-May
	Machinery and equipment	20-Oct
	Office equipment, computer equipment and software	10-Mar
	Enterprise resource planning software	25
	Buildings and improvements	Oct-40
	Depreciation, depletion and amortization
	Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
	Asset retirement obligations
	The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
	The Company’s primary asset retirement obligations relate to future plugging and abandonment costs on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2012 through December 31, 2014:
	In thousands		2014				2013			2012
	Asset retirement obligations at January 1		$	55,787			$	47,171		$	62,625
	Accretion expense		3,366				2,767			3,105
	Revisions		9,916				2,826			(2,871		)
	Plus: Additions for new assets		9,022				6,009			6,679
	Less: Plugging costs and sold assets (1)		(1,383		)		(2,986		)	(22,367		)
	Total asset retirement obligations at December 31		$	76,708			$	55,787		$	47,171
	Less: Current portion of asset retirement obligations at December 31 (2)		1,246				1,434			2,227
	Non-current portion of asset retirement obligations at December 31		$	75,462			$	54,353		$	44,944
	-1	As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion.
	-2	Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.
As of December 31, 2014 and 2013, net property and equipment on the consolidated balance sheets included $64.7 million and $44.4 million, respectively, of net asset retirement costs.
Asset impairment
Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.
Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt issuance costs
Costs incurred in connection with the execution of the Company’s credit facility and amendments thereto are capitalized and amortized over the term of the facility on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. The Company had capitalized costs of $76.1 million and $69.5 million (net of accumulated amortization of $38.1 million and $28.8 million) relating to its long-term debt at December 31, 2014 and 2013, respectively. The increase in 2014 resulted from the capitalization of costs incurred in connection with the Company’s new credit facility and the May 2014 issuances of 3.8% Senior Notes due 2024 and 4.9% Senior Notes due 2044 as discussed in Note 7. Long-Term Debt. For the years ended December 31, 2014, 2013 and 2012, the Company recognized amortization expense associated with capitalized debt issuance costs of $9.3 million, $8.6 million and $5.6 million, respectively, which are reflected in “Interest expense” in the consolidated statements of comprehensive income.
Derivative instruments
The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income under the caption “Gain (loss) on derivative instruments, net.”
Fair value of financial instruments
The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2014 and 2013.
Income taxes
Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.
Earnings per share
Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the years ended December 31, 2014, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012. Weighted average shares and net income per share amounts for 2012 and 2013 have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014.
		Year ended December 31,
In thousands, except per share data		2014				2013			2012
Income (numerator):
Net income - basic and diluted		$	977,341			$	764,219		$	739,385
Weighted average shares (denominator):
Weighted average shares - basic		368,829				368,150			362,680
Non-vested restricted stock		1,929				1,548			980
Stock options		—				—			32
Weighted average shares - diluted		370,758				369,698			363,692
Net income per share:
Basic		$	2.65			$	2.08		$	2.04
Diluted		$	2.64			$	2.07		$	2.03
Foreign currency translation
In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets.
New accounting pronouncement
In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update (“ASU”) No. 2014-09, Revenue from Contracts with Customers (Topic 606). The standard generally requires an entity to identify performance obligations in its contracts, estimate the amount of variable consideration to be received in the transaction price, allocate the transaction price to each separate performance obligation, and recognize revenue as obligations are satisfied. The standard will be effective for annual and interim periods beginning after December 15, 2016. The standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. The Company is evaluating the impact of the provisions of ASU 2014-09; however, the standard is not expected to have a material effect on the Company’s financial position, results of operations or cash flows.
Reclassifications
Prior to 2014, the Company presented charges related to natural gas transportation and processing under the caption “Production taxes and other expenses” or “Production and other expenses to affiliates” in the consolidated statements of comprehensive income. Effective January 1, 2014, such charges are netted within “Crude oil and natural gas sales” or "Crude oil and natural gas sales to affiliates", as applicable. Previously reported amounts have been reclassified to conform to the current year presentation. Reclassified amounts total $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, including transactions with an affiliate totaling $4.7 million for each of those respective years. The reclassifications had no impact on previously reported operating income, net income, current assets, total assets, current liabilities, total liabilities, stockholders' equity or cash flows.

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
	The following table discloses supplemental cash flow information about cash paid for interest and income taxes. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
		Year ended December 31,
	In thousands	2014		2013		2012
	Supplemental cash flow information:
	Cash paid for interest	$	267,384	$	209,815	$	102,043
	Cash paid for income taxes	53,457		29,017		829
	Cash received for income tax refunds	7		174		13,866
	Non-cash investing activities:
	Increase in accrued capital expenditures	290,782		89,482		49,039
	Acquisition of assets through issuance of common stock (Note 11)	—		—		176,563
	Asset retirement obligation additions and revisions, net	18,938		8,835		3,808

Net_Property_and_Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment
	Net property and equipment includes the following at December 31, 2014 and 2013:
		December 31,
	In thousands	2014			2013
	Proved crude oil and natural gas properties	$	17,045,967		$	12,423,878
	Unproved crude oil and natural gas properties	966,080			1,181,268
	Service properties, equipment and other	274,584			236,233
	Total property and equipment	18,286,631			13,841,379
	Accumulated depreciation, depletion and amortization	(4,650,779		)	(3,120,107		)
	Net property and equipment	$	13,635,852		$	10,721,272

Accrued_Liabilities_and_Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other
	Accrued liabilities and other includes the following at December 31, 2014 and 2013:
		December 31,
	In thousands	2014		2013
	Prepaid advances from joint interest owners	$	115,687	$	57,196
	Accrued compensation	39,848		41,757
	Accrued production taxes, ad valorem taxes and other non-income taxes	36,550		35,900
	Deferred tax liabilities	145,349		—
	Accrued interest	60,861		61,216
	Current portion of asset retirement obligations	1,246		1,434
	Other	4,965		610
	Accrued liabilities and other	$	404,506	$	198,113

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments
	The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income under the caption “Gain (loss) on derivative instruments, net.”
	The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the forecasted sale of future crude oil and natural gas production. While the use of these derivative instruments limits the downside risk of adverse price movements, their use also limits future revenues from upward price movements.
	With respect to a fixed price swap contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is less than the swap price, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is greater than the swap price. For a collar contract, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price, and neither party is required to make a payment to the other party if the settlement price for any settlement period is between the floor price and the ceiling price.
	The Company's derivative contracts are settled based upon reported settlement prices on commodity exchanges, with crude oil derivative settlements based on NYMEX West Texas Intermediate ("WTI") pricing or Inter-Continental Exchange ("ICE") pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 6. Fair Value Measurements.
	In the fourth quarter of 2014, substantially all of the Company's outstanding crude oil derivative contracts were settled prior to the expiration of their contractual maturities scheduled through December 2016, resulting in the receipt of cash proceeds and recognition of gains totaling approximately $433 million which are included in the caption “Gain (loss) on derivative instruments, net" in the consolidated statements of comprehensive income for the year ended December 31, 2014. No natural gas derivative contracts in place were liquidated in the fourth quarter of 2014.
	At December 31, 2014, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
	Crude Oil - NYMEX WTI				Ceilings
							Weighted Average
	Period and Type of Contract		Bbls		Range		Price
	July 2015 - December 2015
	Written call options - WTI (1)		2,208,000		$95.85 - $103.75		$	98.36
	Crude Oil - ICE Brent				Ceilings
									Weighted Average
	Period and Type of Contract		Bbls		Range				Price
	July 2015 - December 2015
	Written call options - ICE Brent (1)		368,000		$	107.4			$	107.4
	January 2016 - December 2016
	Written call options - ICE Brent (1)		1,464,000		$	107.7			$	107.7
	Natural Gas - Henry Hub					Swaps Weighted Average Price				Floors				Ceilings
												Weighted Average Price			Weighted Average Price
	Period and Type of Contract		MMBtus							Range				Range
	January 2015 - December 2015
	Swaps - Henry Hub		24,500,000			$	4.27
	Collars - Henry Hub		29,200,000							$3.50 - $3.75		$	3.69	$4.89 - $5.48	$	5.04
	January 2016 - December 2016
	Swaps - Henry Hub		63,110,000			$	3.98
	-1	Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the 2014 fourth quarter. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.
	Derivative gains and losses
	The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period.
			Year ended December 31,
	In thousands		2014				2013				2012
	Cash received (paid) on derivatives:
	Crude oil fixed price swaps (1)		$	331,591			$	(54,289	)		$	(40,238	)
	Crude oil collars (1)		65,310				(16,867		)		(15,341		)
	Natural gas fixed price swaps		(11,551		)		9,601				9,858
	Cash received (paid) on derivatives, net		385,350				(61,555		)		(45,721		)
	Non-cash gain (loss) on derivatives:
	Crude oil fixed price swaps		84,792				(117,580		)		142,567
	Crude oil collars		1,121				(8,587		)		59,911
	Crude oil written call options		3,981				—				—
	Natural gas fixed price swaps		62,699				(4,029		)		(2,741		)
	Natural gas collars		21,816				—				—
	Non-cash gain (loss) on derivatives, net		174,409				(130,196		)		199,737
	Gain (loss) on derivative instruments, net		$	559,759			$	(191,751	)		$	154,016
	-1	Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. The proceeds include $85 million for contracts with original maturities in November and December of 2014, $337 million for contracts with original maturities in 2015, and $11 million for contracts with original maturities in 2016. Of the proceeds, $373 million relates to crude oil swap liquidations and $60 million relates to crude oil collar liquidations.
	Balance sheet offsetting of derivative assets and liabilities
	The Company’s derivative contracts are carried at their fair value in the consolidated balance sheets under the captions “Derivative assets”, “Noncurrent derivative assets”, “Derivative liabilities”, and “Noncurrent derivative liabilities”. Derivative assets and liabilities with the same counterparty that are subject to contractual terms which provide for net settlement are reported on a net basis in the consolidated balance sheets.
	The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value.
			December 31,
	In thousands		2014				2013
	Commodity derivative assets:
	Gross amounts of recognized assets		$	84,415			$	4,213
	Gross amounts offset on balance sheet		—				(597		)
	Net amounts of assets on balance sheet		84,415				3,616
	Commodity derivative liabilities:
	Gross amounts of recognized liabilities		(4,770		)		(125,709		)
	Gross amounts offset on balance sheet		16				27,345
	Net amounts of liabilities on balance sheet		$	(4,754	)		$	(98,364	)
	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
			December 31,
	In thousands		2014				2013
	Derivative assets		$	52,423			$	3,616
	Noncurrent derivative assets		31,992				—
Net amounts of assets on balance sheet		84,415				3,616
Derivative liabilities		(1,645		)		(90,535		)
Noncurrent derivative liabilities		(3,109		)		(7,829		)
Net amounts of liabilities on balance sheet		(4,754		)		(98,364		)
Total derivative assets (liabilities), net		$	79,661			$	(94,748	)

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements
	The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
	•	Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
	•	Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
	•	Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
	A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer.
	Assets and liabilities measured at fair value on a recurring basis
	The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of fixed price swaps, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness.
	The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013.
			Fair value measurements at December 31, 2014 using:
	In thousands		Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps		$	—	$	62,599		$	—	$	62,599
	Collars		—		21,816			—		21,816
	Written call options		—		(4,754		)	—		(4,754		)
	Total		$	—	$	79,661		$	—	$	79,661
			Fair value measurements at December 31, 2013 using:
	In thousands		Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps		$	—	$	(84,893	)	$	—	$	(84,893	)
	Collars		—		(9,855		)	—		(9,855		)
	Total		$	—	$	(94,748	)	$	—	$	(94,748	)
	Assets measured at fair value on a nonrecurring basis
	Certain assets are reported at fair value on a nonrecurring basis in the consolidated financial statements. The following methods and assumptions were used to estimate the fair values for those assets.
	Asset impairments – Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. Due to the unavailability of relevant comparable market data, a discounted cash flow method is used to determine the fair value of proved properties. The discounted cash flow method estimates future cash flows based on management’s estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating and development costs, and a risk-adjusted discount rate. The fair value of proved crude oil and natural gas properties is calculated using significant unobservable inputs (Level 3). The following table sets forth quantitative information about the significant unobservable inputs used by the Company to calculate the fair value of proved crude oil and natural gas properties using a discounted cash flow method.
	Unobservable Input		Assumption
	Future production		Future production estimates for each property
	Forward commodity prices		Forward NYMEX swap prices through 2019 (adjusted for differentials), escalating 3% per year thereafter
	Operating and development costs		Estimated costs for the current year, escalating 3% per year thereafter
	Productive life of field		Ranging from 0 to 50 years
	Discount rate		10%
	Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
	Impairments of proved properties amounted to $324.3 million for the year ended December 31, 2014, of which $255.0 million was recognized in the fourth quarter resulting from a significant decrease in crude oil prices in late 2014 that indicated the carrying amounts for certain fields were not recoverable. The 2014 impairments reflected fair value adjustments primarily concentrated in the Buffalo Red River units ($96.9 million), the Medicine Pole Hills units ($75.9 million), various non-core areas in the South region ($39.7 million), non-Bakken areas of North Dakota and Montana ($18.4 million), and certain emerging areas with limited production history and costly reserve additions ($75.2 million). The impaired properties were written down to their estimated fair value totaling approximately $101.0 million. Impairments for 2014 also include an $18.2 million lower of cost or market adjustment for crude oil inventories.
	Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2014, 2013, and 2012, reflecting amortization of undeveloped leasehold costs on properties that management expects will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. In 2014, undeveloped leasehold costs for a prospect in Texas were written down to $14.2 million due to changes in drilling plans in response to unsuccessful results and lower crude oil prices, which resulted in the recognition of $92.4 million of non-producing leasehold impairment charges for the prospect, of which $84.6 million was recognized in the fourth quarter.
	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income.
			Year ended December 31,
	In thousands		2014		2013			2012
	Proved property impairments		$	324,302	$	51,805		$	4,332
	Unproved property impairments		292,586		168,703			117,942
	Total		$	616,888	$	220,508		$	122,274
	Financial instruments not recorded at fair value
	The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements.
			December 31, 2014					December 31, 2013
	In thousands		Carrying Amount		Fair Value			Carrying Amount		Fair Value
	Debt:
	Credit facility		$	165,000	$	165,000		$	275,000	$	275,000
	Note payable		16,457		14,900			18,470		16,500
	8.25% Senior Notes due 2019 (1)		—		—			298,305		327,800
	7.375% Senior Notes due 2020		198,850		213,000			198,695		223,700
	7.125% Senior Notes due 2021		400,000		421,000			400,000		450,300
	5% Senior Notes due 2022		2,022,949		1,857,900			2,025,362		2,063,300
	4.5% Senior Notes due 2023		1,500,000		1,372,800			1,500,000		1,519,400
	3.8% Senior Notes due 2024		996,622		868,700			—		—
	4.9% Senior Notes due 2044		698,037		572,400			—		—
	Total debt		$	5,997,915	$	5,485,700		$	4,715,832	$	4,876,000
	(1) These senior notes were redeemed in July 2014. See Note 7. Long-Term Debt for further discussion.
	The fair value of credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and is classified as Level 2 in the fair value hierarchy.
	The fair value of the note payable is determined using a discounted cash flow approach based on the interest rate and payment terms of the note payable and an assumed discount rate. The fair value of the note payable is significantly influenced by the discount rate assumption, which is derived by the Company and is unobservable. Accordingly, the fair value of the note payable is classified as Level 3 in the fair value hierarchy.
	The fair values of the 8.25% Senior Notes due 2019 (“2019 Notes”), the 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy.
	The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt
	Long-term debt consists of the following at December 31, 2014 and 2013:
			December 31,
	In thousands		2014			2013
	Credit facility		$	165,000		$	275,000
	Note payable		16,457			18,470
	8.25% Senior Notes due 2019 (1)		—			298,305
	7.375% Senior Notes due 2020 (2)		198,850			198,695
	7.125% Senior Notes due 2021 (3)		400,000			400,000
	5% Senior Notes due 2022 (4)		2,022,949			2,025,362
	4.5% Senior Notes due 2023 (3)		1,500,000			1,500,000
	3.8% Senior Notes due 2024 (5)		996,622			—
	4.9% Senior Notes due 2044 (6)		698,037			—
	Total debt		5,997,915			4,715,832
	Less: Current portion of long-term debt		2,078			2,011
	Long-term debt, net of current portion		$	5,995,837		$	4,713,821
	-1	The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. The 2019 Notes were redeemed in July 2014 as discussed further below.
	-2	The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively.
	-3	These notes were sold at par and are recorded at 100% of face value.
	-4	The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively.
	-5	The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014.
	-6	The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014.
	Credit facility
	In May 2014, the Company entered into a new unsecured credit facility that provides for increased aggregate commitments and an extended maturity beyond the term of its previous credit facility. The new credit facility matures on May 16, 2019 and had aggregate commitments totaling $1.75 billion at December 31, 2014. The new credit facility replaced the Company’s previous $1.5 billion unsecured credit facility that was due to mature on July 1, 2015.
	In February 2015, aggregate commitments on the credit facility were increased to $2.5 billion to provide additional liquidity if needed to maintain the Company's growth strategy, take advantage of business opportunities, and fund its capital program and commitments. Credit facility commitments can be further increased up to a total of $4.0 billion upon agreement between the Company and participating lenders.
	The Company had $165 million of outstanding borrowings on its credit facility at December 31, 2014, which subsequently increased to $605 million at February 17, 2015 as a result of additional borrowings incurred for the payment of amounts owed in connection with the Company's 2014 drilling program and to fund a portion of its 2015 drilling program. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior unsecured debt.
	After increasing its aggregate commitments in February 2015, the Company had approximately $1.9 billion of borrowing availability on its credit facility at February 17, 2015. The Company incurs commitment fees based on currently assigned credit ratings of 0.225% per annum of the daily average amount of unused borrowing availability.
	The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity. The Company was in compliance with this covenant at December 31, 2014.
	Senior notes
	In May 2014, the Company issued $1.0 billion of 3.8% Senior Notes due 2024 and $700 million of 4.9% Senior Notes due 2044 and received total net proceeds of approximately $1.68 billion after deducting the initial purchasers' fees. The Company used a portion of the net proceeds from the offerings to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of $1.01 billion, and to finance the redemption of its 2019 Notes as discussed below. The remaining net proceeds were used to fund a portion of the Company's 2014 capital program and for general corporate purposes.
	In July 2014, the Company redeemed its 2019 Notes for $317.5 million, representing a make-whole amount calculated in accordance with the terms of the 2019 Notes and related indenture. The Company recognized a pre-tax loss of $24.5 million related to the redemption, which includes the make-whole premium and the write-off of deferred financing costs and unaccreted debt discount and is reflected under the caption “Loss on extinguishment of debt" in the consolidated statements of comprehensive income for the year ended December 31, 2014.
	The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations.
			2020 Notes		2021 Notes	2022 Notes		2023 Notes	2024 Notes	2044 Notes
	Maturity date		Oct 1, 2020		April 1, 2021	Sep 15, 2022		April 15, 2023	June 1, 2024	June 1, 2044
	Interest payment dates		April 1,Oct. 1		April 1, Oct. 1	March 15,  Sept. 15		April 15, Oct. 15	June 1, Dec. 1	June 1, Dec. 1
	Call premium redemption period (1)		1-Oct-15		April 1, 2016	15-Mar-17		—	—	—
	Make-whole redemption period (2)		1-Oct-15		April 1, 2016	15-Mar-17		Jan 15, 2023	Mar 1, 2024	Dec 1, 2043
	Equity offering redemption period (3)		—		—	15-Mar-15		—	—	—
	-1	On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption.
	-2	At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
	-3	At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption.
	The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
	The indentures governing the Company's senior notes contain covenants that, among others, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2014. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes.
	Note payable
	In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10-year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022. Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2014.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes
	The items comprising the provision for income taxes are as follows for the periods presented:
			Year ended December 31,
	In thousands		2014			2013			2012
	Current income tax provision:
	United States federal		$	—		$	6,193		$	9,191
	Various states		20			16			1,326
	Total current income tax provision		20			6,209			10,517
	Deferred income tax provision:
	United States federal		527,315			403,002			383,157
	Various states		57,362			39,619			22,137
	Total deferred income tax provision		584,677			442,621			405,294
	Total provision for income taxes		$	584,697		$	448,830		$	415,811
	The provision for income taxes differs from the amount computed by applying the United States statutory federal income tax rate to income before income taxes. The sources and tax effects of the difference are as follows:
			Year ended December 31,
	In thousands		2014			2013			2012
	Expected income tax expense based on US statutory tax rate of 35%		$	546,713		$	424,567		$	404,319
	State income taxes, net of federal benefit		42,169			25,838			15,213
	Canadian valuation allowance		4,389			—			—
	Effect of differing statutory tax rate in Canada		(1,900		)	—			—
	Other, net		(6,674		)	(1,575		)	(3,721		)
	Provision for income taxes		$	584,697		$	448,830		$	415,811
	The components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows:
			December 31,
	In thousands		2014			2013
	Current:
	Deferred tax assets (1)
	Non-cash losses on derivatives		$	—		$	33,029
	Other		3,274			2,288
	Total current deferred tax assets		3,274			35,317
	Deferred tax liabilities
	Non-cash gains on derivatives		(19,293		)	—
	Gain on derivative liquidations		(128,198		)	—
	Other		(1,132		)	(645		)
	Total current deferred tax liabilities		(148,623		)	(645		)
	Net current deferred tax assets (liabilities) (2)		(145,349		)	34,672
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards		60,904			41,791
	Non-cash losses on derivatives		—			2,975
	Alternative minimum tax carryforwards		38,715			38,689
	Equity compensation		22,255			16,961
	Other		10,545			3,259
	Total noncurrent deferred tax assets		132,419			103,675
	Canadian valuation allowance		(4,389		)	—
	Total noncurrent deferred tax assets, net of valuation allowance		128,030			103,675
	Deferred tax liabilities
	Property and equipment		(2,254,343		)	(1,840,331		)
	Non-cash gains on derivatives		(10,976		)	—
	Other		(4,158		)	(156		)
	Total noncurrent deferred tax liabilities		(2,269,477		)	(1,840,487		)
	Net noncurrent deferred tax liabilities		(2,141,447		)	(1,736,812		)
	Net deferred tax liabilities		$	(2,286,796	)	$	(1,702,140	)
	-1	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively.
	-2	The net liability balance at December 31, 2014 is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. The net asset balance at December 31, 2013 is included in the caption "Deferred and prepaid taxes" in the consolidated balance sheets.
	As of December 31, 2014, the Company had federal and state net operating loss carryforwards of $19 million and $1.39 billion, respectively. The federal net operating loss carryforward will begin expiring in 2033. The Oklahoma net operating loss carryforward of $1.37 billion will begin to expire in 2027. The remainder of the state net operating loss carryforwards will begin expiring in 2017. The Company has alternative minimum tax credit carryforwards of $39 million that have no expiration date. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in the U.S. federal, U.S. state and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2011.
	We recorded a $4.4 million valuation allowance for deferred tax assets at December 31, 2014. Our Canadian subsidiary generated operating loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income.

Lease_Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Lease Commitments	Lease Commitments
	The Company’s operating lease obligations primarily represent leases for office equipment, communication towers, and tanks for storage of hydraulic fracturing fluids. Lease payments associated with operating leases for the years ended December 31, 2014, 2013 and 2012 were $8.0 million, $3.0 million and $2.2 million, respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2014, the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows:
	In thousands	Total amount
	2015	$	4,953
	2016	3,256
	2017	1,234
	2018	856
	2019	300
	Thereafter	3,468
	Total obligations	$	14,067

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies
	Included below is a discussion of various future commitments of the Company as of December 31, 2014. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.
	Drilling commitments – As of December 31, 2014, the Company had drilling rig contracts with various terms extending through July 2018. These contracts were entered into in the ordinary course of business to ensure rig availability to allow the Company to execute its business objectives in its strategic plays. Future commitments as of December 31, 2014 total approximately $610 million, of which $246 million is expected to be incurred in 2015, $212 million in 2016, $123 million in 2017, and $29 million in 2018.
	Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have varying terms extending as far as 2025, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2014 under the operational pipeline transportation arrangements amount to approximately $969 million, of which $182 million is expected to be incurred in 2015, $187 million in 2016, $181 million in 2017, $176 million in 2018, $140 million in 2019, and $103 million thereafter. Included in these amounts is approximately $96 million of commitments associated with a 5-year joint tariff arrangement between an unaffiliated party and an affiliate controlled by the Company's principal shareholder up through February 13, 2015 as discussed in Note 11. Related Party Transactions.
	Further, the Company is a party to an additional 5-year firm transportation commitment for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. Future commitments under the non-operational arrangement total approximately $260 million at December 31, 2014. This commitment represents aggregate transportation charges expected to be incurred over the 5-year term beginning when the proposed pipeline project is completed and becomes operational. The exact timing of the commencement of pipeline operations is not known due to uncertainties involving matters such as regulatory approvals, resolution of legal and environmental disputes, construction progress, and the ultimate probability of pipeline completion. Accordingly, the timing of the Company’s obligations under this non-operational arrangement cannot be predicted with certainty and may not be incurred on a ratable basis over a calendar year or may not be incurred at all.
	The Company’s pipeline commitments are for production primarily in the North region where the Company allocates a significant portion of its capital expenditures. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future.
	Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month over the period from January 2015 through June 2016 for use in the normal course of drilling operations. Over the contract term, the Company has committed to purchase a total of approximately 31 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of December 31, 2014 total approximately $96 million, of which $64 million is expected to be incurred in 2015 and $32 million is expected to be incurred in 2016.
	Litigation – In November 2010, an alleged class action was filed against the Company alleging the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The Company has responded to the petition, denied the allegations and raised a number of affirmative defenses. Discovery is ongoing and information and documents continue to be exchanged. The Company is not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the action will have on its financial condition, results of operations or cash flows due to the preliminary status of the matter, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, the production years involved, and the ultimate potential outcome of the matter. The class has not been certified. The class certification hearing is currently scheduled for May 25, 2015. Plaintiffs have indicated that if the class is certified they may seek damages in excess of $165 million which may increase with the passage of time, a majority of which would be comprised of interest. The Company disputes plaintiffs’ claims, disputes that the case meets the requirements for a class action and is vigorously defending the case.
	The Company is involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims and other matters. While the outcome of these legal matters cannot be predicted with certainty, the Company does not expect them to have a material effect on its financial condition, results of operations or cash flows. As of December 31, 2014 and 2013, the Company has recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $2.9 million and $1.7 million, respectively, for various matters, none of which are believed to be individually significant.
	Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Related_Party_Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions
	The Company sells a portion of its natural gas production to affiliates. For the years ended December 31, 2014, 2013, and 2012, these sales amounted to $95.1 million, $100.4 million, and $57.0 million, respectively, net of transportation and processing costs, and are included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income. At December 31, 2014 and 2013, $13.1 million and $12.7 million, respectively, was due to the Company from these affiliates, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets. At December 31, 2014 and 2013, $0.3 million and $0.2 million was due from the Company to affiliates for transportation and processing costs associated with these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
	The Company engages in crude oil trades with an affiliate from time to time to obtain space on pipeline systems in the Company's operating areas. For the year ended December 31, 2012, crude oil sales to the affiliate totaled 21,000 barrels generating sales proceeds of $1.9 million, which is included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income. There were no crude oil sales to the affiliate in 2014 or 2013. In 2013 and 2012, the Company purchased 30,000 barrels and 2,000 barrels, respectively, from the affiliate for $3.0 million and $0.2 million, respectively.
	The Company incurs affiliate costs associated with field services such as compression and drilling rig services, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. The Company capitalized costs of $5.9 million, $5.7 million and $5.0 million in 2014, 2013, and 2012, respectively, associated with drilling rig services provided by an affiliate. Production and other expenses attributable to these affiliate transactions were $5.1 million, $1.4 million and $2.0 million for the years ended December 31, 2014, 2013, and 2012, respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $58.2 million, $48.5 million and $32.7 million for the years ended December 31, 2014, 2013, and 2012, respectively. At December 31, 2014 and 2013, $5.6 million and $5.1 million, respectively, was due to these affiliates related to these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
	The Company is a party to 5-year firm transportation commitments under a joint tariff arrangement to guarantee pipeline access capacity totaling 10,000 barrels of crude oil per day on pipelines operated by an unaffiliated party and an affiliated party controlled by the Company's principal shareholder. The commitments require the Company to pay joint tariff transportation charges totaling $5.25 per barrel regardless of the amount of pipeline capacity used, which will be allocated between the affiliated party and unaffiliated party. Future commitments under the joint tariff arrangement, a portion of which will be allocated to the affiliate, total approximately $96 million at December 31, 2014, representing aggregate joint tariff transportation charges expected to be incurred over the 5-year term. The Company expects to begin satisfying its commitments under the arrangement beginning in the first quarter of 2015. The Company expects it will receive invoices from, and submit payments to, the unaffiliated party for fees owed under the arrangement, with the unaffiliated party being responsible for allocating a portion of such fees to the affiliated party.
	The affiliate transactions described above, with the exception of drilling rig services, represent transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder up through February 13, 2015, at which time it was sold to an unaffiliated third party. After February 13, 2015, the transactions above, to the extent they continue with the acquirer of Hiland, will no longer be considered related party transactions.
	Certain officers and other key employees of the Company own or control entities that own working and royalty interests in wells operated by the Company. The Company paid revenues to these affiliates, including royalties, of $1.7 million, $2.3 million, and $38.3 million and received payments from these affiliates of $0.8 million, $1.3 million, and $38.5 million during the years ended December 31, 2014, 2013, and 2012, respectively, relating to the operations of the respective properties. The Company also paid to these affiliates $0.3 million in 2012 for their share of proceeds from undeveloped leasehold sales, with no such payments in 2013 or 2014. At December 31, 2014 and 2013, $0.2 million and $0.4 million was due from these affiliates and approximately $0.1 million and $0.2 million was due to these affiliates, respectively, relating to these transactions.
	Prior to July 2012, the Company leased office space under an operating lease from an entity owned by the Company’s principal shareholder. Rents paid associated with the leases totaled approximately $0.7 million for the year ended December 31, 2012.
	The Company allows certain affiliates to use its corporate aircraft and crews and has used the aircraft and crews of those same affiliates from time to time in order to facilitate efficient transportation of Company personnel. The rates charged between the parties vary by type of aircraft used. For usage during 2014, 2013, and 2012, the Company charged affiliates approximately $51,000, $55,000, and $112,000, respectively, for use of its corporate aircraft, crews, fuel, utilities and reimbursement of expenses and received $39,000 and $379,000 from affiliates in 2014 and 2013, respectively. The Company was charged $97,000, $51,000, and $102,000, respectively, by affiliates for use of their aircraft, crews, and reimbursement of expenses during 2014, 2013, and 2012 and paid $34,000 and $238,000 to the affiliates in 2014 and 2013, respectively.
	The Company incurred costs for various field projects that have been ongoing with an entity that became an affiliate of the Company in the third quarter of 2014. The total amount invoiced and capitalized for the second half of 2014 associated with the projects was $1.8 million. The total amount paid, a portion of which was billed to other interest owners, was $1.9 million for the second half of 2014 and approximately $1.2 million was owed by the Company at December 31, 2014, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
	In August 2012, the Company acquired the assets of Wheatland Oil Inc. ("Wheatland") through the issuance of shares of the Company’s common stock. Wheatland is owned 75% by the Harold G. Hamm Trust (formerly the Revocable Inter Vivos Trust of Harold G. Hamm), a trust of which Harold G. Hamm, the Company’s Chief Executive Officer, Chairman of the Board and principal shareholder is the trustee and sole beneficiary, and 25% by the Company’s Vice Chairman of Strategic Growth Initiatives, Jeffrey B. Hume. As consideration for the acquisition, the Company issued approximately 7.8 million shares of its common stock, par value $0.01 per share, to the shareholders of Wheatland in accordance with the terms of the arrangement. The fair value of the consideration transferred by the Company at closing was approximately $279 million. In 2013, Wheatland paid the Company approximately $0.5 million upon final settlement of purchase price adjustments under the terms of the arrangement. For accounting purposes, the Wheatland acquisition represented a transaction between entities under common control as Mr. Hamm is the controlling shareholder of both the Company and Wheatland. Accordingly, the Company recorded the assets acquired and liabilities assumed at Wheatland’s carrying amount. The net book basis of Wheatland’s assets was approximately $82 million, primarily representing $177 million for acquired crude oil and natural gas properties partially offset by $38 million of joint interest obligations assumed, $0.6 million of asset retirement obligations assumed and $57 million of deferred income tax liabilities recognized.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2014
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation
	The Company has granted stock options to employees pursuant to the Continental Resources, Inc. 2000 Stock Option Plan (“2000 Plan”) and restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income, is reflected in the table below for the periods presented.
		Year ended December 31,
	In thousands	2014			2013			2012
	Non-cash equity compensation	$	54,353		$	39,890		$	29,057
	Restricted stock
	In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of December 31, 2014, the Company had a maximum of 18,104,686 shares of restricted stock available to grant to officers, directors and select employees under the 2013 Plan.
	Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock or to receive dividends, subject to forfeiture. Restricted stock grants generally vest over periods ranging from one to three years.
	A summary of changes in non-vested restricted shares from December 31, 2011 to December 31, 2014 is presented below.
		Number of		Weighted
		non-vested		average
		shares		grant-date
				fair value
	Non-vested restricted shares at December 31, 2011	2,396,688		$	24.33
	Granted	1,832,056		36.73
	Vested	(889,446	)	22.63
	Forfeited	(80,374	)	29.53
	Non-vested restricted shares at December 31, 2012	3,258,924		$	31.64
	Granted	522,518		48.98
	Vested	(929,618	)	23.65
	Forfeited	(137,512	)	35.96
	Non-vested restricted shares at December 31, 2013	2,714,312		$	37.5
	Granted	1,424,764		61.11
	Vested	(1,007,166	)	35.91
	Forfeited	(453,146	)	44.9
	Non-vested restricted shares at December 31, 2014	2,678,764		$	49.4
	The grant date fair value of restricted stock represents the closing market price of the Company’s common stock on the date of grant. Compensation expense for a restricted stock grant is a fixed amount determined at the grant date fair value and is recognized ratably over the vesting period as services are rendered by employees and directors. The expected life of restricted stock is based on the non-vested period that remains subsequent to the date of grant. There are no post-vesting restrictions related to the Company’s restricted stock. The fair value of restricted stock that vested during 2014, 2013 and 2012 at the vesting date was $58.2 million, $49.4 million and $33.0 million, respectively. As of December 31, 2014, there was approximately $72 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized ratably over a weighted average period of 1.4 years.
	Stock options
	Effective October 1, 2000, the Company adopted the 2000 Plan and granted stock options to certain eligible employees. On November 10, 2005, the 2000 Plan was terminated. As of March 31, 2012, all options issued under the 2000 Plan had been exercised or expired. The following table summarizes stock option activity under the 2000 Plan for the periods presented:
		Outstanding					Exercisable
		Number of		Weighted			Number of			Weighted
		options		average			options			average
				exercise						exercise
				price						price
	Outstanding at December 31, 2011	173,000		$	0.36		173,000			$	0.36
	Exercised	(173,000	)	$	0.36
	Outstanding at December 31, 2012	—		—			—			—
	The intrinsic value of a stock option is the amount by which the value of the underlying stock exceeds the exercise price of the option at its exercise date. The total intrinsic value of options exercised during the year ended December 31, 2012 was $7.6 million.

Property_Acquisitions_and_Disp

Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2014
Extractive Industries [Abstract]
Property Acquisitions and Dispositions	Property Acquisitions and Dispositions
	2012 Acquisitions
	In December 2012, the Company acquired certain producing and undeveloped properties in the Bakken play of North Dakota from a third party for $663.3 million, of which $477.1 million was allocated to producing properties. In the transaction, the Company acquired interests in approximately 119,000 net acres as well as producing properties with production of approximately 6,500 net barrels of oil equivalent per day.
	In August 2012, the Company acquired the assets of Wheatland Oil Inc. through the issuance of shares of the Company’s common stock. See Note 11. Related Party Transactions for further discussion.
	In February 2012, the Company acquired certain producing and undeveloped properties in the Bakken play of North Dakota from a third party for $276 million, of which $51.7 million was allocated to producing properties. In the transaction, the Company acquired interests in approximately 23,100 net acres as well as producing properties with production of approximately 1,000 net barrels of oil equivalent per day.
	2012 Dispositions
	In December 2012, the Company sold its producing crude oil and natural gas properties and supporting assets in its East region to a third party for $126.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $68.0 million, which included the effect of removing $8.3 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
	In June 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Oklahoma to a third party for $15.9 million and recognized a pre-tax gain on the transaction of $15.9 million, which included the effect of removing $0.6 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
	In February 2012, the Company assigned certain non-strategic leaseholds and producing properties located in Wyoming to a third party for $84.4 million. In connection with the transaction, the Company recognized a pre-tax gain of $50.1 million, which included the effect of removing $11.1 million of asset retirement obligations for the disposed properties previously recognized by the Company that were assumed by the buyer. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.
	2014 Disposition and Related Joint Development Agreement
	In September 2014, the Company entered into an agreement with a U.S. subsidiary of SK E&S Co. Ltd (“SK”) of South Korea to jointly develop a significant portion of the Company’s Northwest Cana natural gas properties. Under the agreement, Continental sold a 49.9% interest in approximately 44,000 net acres in the Northwest Cana area of the Anadarko Woodford Shale play, along with interests in 37 producing wells. Continental received approximately $90 million in cash at closing and SK has committed to pay Continental an additional $270 million to fund, or carry, 50% of Continental's remaining share of future drilling and completion costs over a period of approximately five years extending into 2019. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues and the transaction did not have a material impact on results of operations for the year ended December 31, 2014.
	The gains on the dispositions described above are included in the caption “Gain on sale of assets, net” in the consolidated statements of comprehensive income.

Crude_Oil_and_Natural_Gas_Prop

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude Oil and Natural Gas Property Information	Crude Oil and Natural Gas Property Information
	The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014, the Company initiated exploratory drilling activities in Canada. Through December 31, 2014, those drilling activities have not had a material impact on the Company's total capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tables below.
	The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012.
			Year ended December 31,
	In thousands		2014			2013			2012
	Crude oil and natural gas sales (1)		$	4,203,022		$	3,573,431		$	2,349,500
	Production expenses		(352,472		)	(282,197		)	(195,440		)
	Production taxes and other expenses (1)		(349,760		)	(298,787		)	(198,505		)
	Exploration expenses		(50,067		)	(34,947		)	(23,507		)
	Depreciation, depletion, amortization and accretion		(1,338,351		)	(953,796		)	(683,207		)
	Property impairments		(616,888		)	(220,508		)	(122,274		)
	Income taxes		(559,311		)	(659,783		)	(428,095		)
	Results from crude oil and natural gas producing activities		$	936,173		$	1,123,413		$	698,472
	-1	Natural gas transportation and processing charges totaling $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, have been reclassified from "Production taxes and other expenses" to "Crude oil and natural gas sales" to conform to the current year presentation as discussed in Note 1. Organization and Summary of Significant Accounting Policies.
	Costs incurred in crude oil and natural gas activities
	Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2014, 2013 and 2012 are presented below:
			Year ended December 31,
	In thousands		2014			2013			2012
	Property Acquisition Costs:
	Proved		$	48,917		$	16,604		$	738,415
	Unproved		409,529			546,881			745,601
	Total property acquisition costs		458,446			563,485			1,484,016
	Exploration Costs		863,606			687,767			857,681
	Development Costs		3,670,448			2,549,203			1,975,660
	Total		$	4,992,500		$	3,800,455		$	4,317,357
	Exploration costs above include asset retirement costs of $1.2 million, $1.8 million and $3.3 million and development costs above include asset retirement costs of $19.1 million, $6.0 million and $1.0 million for the years ended December 31, 2014, 2013 and 2012, respectively.
	Aggregate capitalized costs
	Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2014 and 2013 are as follows:
			December 31,
	In thousands		2014			2013
	Proved crude oil and natural gas properties		$	17,045,967		$	12,423,878
	Unproved crude oil and natural gas properties		966,080			1,181,268
	Total		18,012,047			13,605,146
	Less accumulated depreciation, depletion and amortization		(4,601,864		)	(3,083,180		)
	Net capitalized costs		$	13,410,183		$	10,521,966
	Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income as dry hole costs, a component of “Exploration expenses”. Where sufficient hydrocarbons have been discovered to justify further exploration or appraisal activities, exploratory drilling costs are deferred under the caption “Net property and equipment” on the consolidated balance sheets pending the outcome of those activities.
	On a quarterly basis, operating and financial management review the status of all deferred exploratory drilling costs in light of ongoing exploration activities—in particular, whether the Company is making sufficient progress in its ongoing exploration and appraisal efforts. If management determines that future appraisal drilling or development activities are not likely to occur, any associated exploratory well costs are expensed in that period of determination.
	The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
			Year ended December 31,
	In thousands		2014			2013			2012
	Balance at January 1		$	152,775		$	92,699		$	128,123
	Additions to capitalized exploratory well costs pending determination of proved reserves		627,853			548,933			485,530
	Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves		(671,618		)	(479,507		)	(520,187		)
	Capitalized exploratory well costs charged to expense		(15,589		)	(9,350		)	(767		)
	Balance at December 31		$	93,421		$	152,775		$	92,699
	Number of gross wells		119			67			46
	As of December 31, 2014, exploratory drilling costs of $4.5 million, representing one well, were suspended one year beyond the completion of drilling and is expected to be fully evaluated in 2015. Of the suspended costs, $0.5 million was incurred in 2014 and $4.0 million was incurred in 2013.

Supplemental_Crude_Oil_and_Nat

Supplemental Crude Oil and Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2014
Supplemental Crude Oil and Natural Gas Information [Abstract]
Supplemental Crude Oil and Natural Gas Information (Unaudited)	Supplemental Crude Oil and Natural Gas Information (Unaudited)
	The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 99%, 99%, and 99% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2014, 2013, and 2012, respectively. Properties comprising 99% of proved crude oil reserves and 95% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2014. Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been recorded for the Company's Canadian operations at December 31, 2014.
	Proved reserves are estimated quantities of crude oil and natural gas which geological and engineering data demonstrate with reasonable certainty to be economically producible in future periods from known reservoirs under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured, and estimates of engineers other than the Company’s might differ materially from the estimates set forth herein. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Periodic revisions to the estimated reserves and future cash flows may be necessary as a result of a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Accordingly, reserve estimates may differ significantly from the quantities of crude oil and natural gas ultimately recovered.
	Reserves at December 31, 2014, 2013 and 2012 were computed using the 12-month unweighted average of the first-day-of-the-month commodity prices as required by SEC rules.
	Natural gas imbalance receivables and payables for each of the three years ended December 31, 2014, 2013 and 2012 were not material and have not been included in the reserve estimates.
	Proved crude oil and natural gas reserves
	Changes in proved reserves were as follows for the periods presented:
		Crude Oil			Natural Gas			Total
		(MBbls)			(MMcf)			(MBoe)
	Proved reserves as of December 31, 2011	326,133			1,093,832			508,438
	Revisions of previous estimates	33,272			(174,736	)		4,149
	Extensions, discoveries and other additions	166,844			400,848			233,652
	Production	(25,070	)		(63,875	)		(35,716	)
	Sales of minerals in place	(7,165	)		(4,046	)		(7,838	)
	Purchases of minerals in place	67,149			89,061			81,992
	Proved reserves as of December 31, 2012	561,163			1,341,084			784,677
	Revisions of previous estimates	(55,783	)		(241,623	)		(96,054	)
	Extensions, discoveries and other additions	267,009			1,065,870			444,654
	Production	(34,989	)		(87,730	)		(49,610	)
	Sales of minerals in place	—			—			—
	Purchases of minerals in place	388			419			458
	Proved reserves as of December 31, 2013	737,788			2,078,020			1,084,125
	Revisions of previous estimates	(67,151	)		(244,783	)		(107,949	)
	Extensions, discoveries and other additions	239,526			1,206,569			440,621
	Production	(44,530	)		(114,295	)		(63,579	)
	Sales of minerals in place	(123	)		(18,623	)		(3,227	)
	Purchases of minerals in place	850			1,498			1,100
	Proved reserves as of December 31, 2014	866,360			2,908,386			1,351,091
	Revisions of previous estimates. Revisions represent changes in previous reserve estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
	Upward revisions to crude oil reserves in 2012 resulted from better than anticipated production performance. Downward revisions to natural gas reserves in 2012 resulted from the removal of proved undeveloped ("PUD") reserves for certain dry gas properties not expected to be developed given the pricing environment for natural gas.
	Downward revisions to crude oil and natural gas reserves in 2013 primarily represented the removal of PUD reserves resulting from a decision in 2013 to focus the Company's drilling program on certain areas of the Bakken and SCOOP plays with more attractive rates of return and multi-well pad drilling capabilities, while building on success in the Company's development of the Lower Three Forks reservoirs in the Bakken.
	Downward revisions to crude oil and natural gas reserves in 2014 resulted from the Company refining its drilling program and reducing its planned rig count in response to the significant decrease in crude oil prices in the latter part of 2014, which contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. The drilling program was refined to concentrate efforts in core areas of the Bakken and SCOOP that provide the opportunity to improve recoveries and rates of return. One element leading to the removal is an increased emphasis on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized. Further, in the SCOOP play the Company removed certain PUD locations originally planned to be developed with standard lateral drilling lengths in favor of PUDs to be developed with extended length laterals in similar locations that provide the opportunity for improved well productivity and economics. The combination of these and other factors resulted in the removal of 53 MMBo and 315 Bcf (105 MMBoe) of PUD reserves in 2014.
	Extensions, discoveries and other additions. These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.
	Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in the Bakken field. Proved reserve additions in the Bakken totaled 184 MMBo and 231 Bcf (222 MMBoe) for the year ended December 31, 2014. Additionally, 2014 extensions and discoveries were significantly impacted by successful drilling results in the SCOOP play, resulting in 55 MMBo and 921 Bcf (208 MMBoe) of proved reserve additions during the year. Significant progress continued to be made in 2014 in developing and expanding the Company's Bakken and SCOOP assets, both laterally and vertically, through strategic exploration, development, planning and technology.
	Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 13. Property Acquisitions and Dispositions for a discussion of notable dispositions.
	Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. See Note 13. Property Acquisitions and Dispositions for further discussion of notable acquisitions.
	The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2014, 2013 and 2012:
		December 31,
		2014			2013			2012
	Proved Developed Reserves
	Crude oil (MBbl)	342,137			278,630			226,870
	Natural Gas (MMcf)	962,051			768,969			545,499
	Total (MBoe)	502,479			406,792			317,786
	Proved Undeveloped Reserves
	Crude oil (MBbl)	524,223			459,158			334,293
	Natural Gas (MMcf)	1,946,335			1,309,051			795,585
	Total (MBoe)	848,612			677,333			466,891
	Total Proved Reserves
	Crude oil (MBbl)	866,360			737,788			561,163
	Natural Gas (MMcf)	2,908,386			2,078,020			1,341,084
	Total (MBoe)	1,351,091			1,084,125			784,677
	Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves that require incremental capital expenditures to recover. Natural gas is converted to barrels of crude oil equivalent using a conversion factor of six thousand cubic feet per barrel of crude oil based on the average equivalent energy content of natural gas compared to crude oil.
	Standardized measure of discounted future net cash flows relating to proved crude oil and natural gas reserves
	The standardized measure of discounted future net cash flows presented in the following table was computed using the 12-month unweighted average of the first-day-of-the-month commodity prices, the costs in effect at December 31 of each year and a 10% discount factor. The Company cautions that actual future net cash flows may vary considerably from these estimates. Although the Company’s estimates of total proved reserves, development costs and production rates were based on the best available information, the development and production of the crude oil and natural gas reserves may not occur in the periods assumed. Actual prices realized, costs incurred and production quantities may vary significantly from those used. Therefore, the estimated future net cash flow computations should not be considered to represent the Company’s estimate of the expected revenues or the current value of existing proved reserves.
	The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2014, 2013 and 2012.
		December 31,
	In thousands	2014				2013				2012
	Future cash inflows	$	90,867,459			$	78,646,274			$	54,362,574
	Future production costs	(25,799,221		)		(21,333,460		)		(13,103,469		)
	Future development and abandonment costs	(12,842,174		)		(10,250,789		)		(8,295,130		)
	Future income taxes	(13,800,737		)		(12,447,127		)		(8,500,766		)
	Future net cash flows	38,425,327				34,614,898				24,463,209
	10% annual discount for estimated timing of cash flows	(19,992,293		)		(18,319,131		)		(13,282,852		)
	Standardized measure of discounted future net cash flows	$	18,433,034			$	16,295,767			$	11,180,357
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $84.54, $91.50, and $86.56 per barrel at December 31, 2014, 2013 and 2012, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $6.06, $5.36, and $4.31 per Mcf at December 31, 2014, 2013 and 2012, respectively. Future cash flows are reduced by estimated future costs to develop and produce the proved reserves, as well as certain abandonment costs, based on year-end cost estimates assuming continuation of existing economic conditions. The expected tax benefits to be realized from the utilization of net operating loss carryforwards and tax credits are used in the computation of future income tax cash flows.
The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years.
	December 31,
In thousands	2014				2013				2012
Standardized measure of discounted future net cash flows at January 1	$	16,295,767			$	11,180,357			$	7,505,356
Extensions, discoveries and improved recoveries, less related costs	5,516,528				6,613,665				3,724,136
Revisions of previous quantity estimates	(1,755,366		)		(1,765,300		)		254,493
Changes in estimated future development and abandonment costs	476,665				1,942,585				(298,148		)
Purchases (sales) of minerals in place, net	(3,196		)		12,012				1,171,047
Net change in prices and production costs	(1,925,349		)		263,541				(530,515		)
Accretion of discount	1,629,576				1,118,036				750,536
Sales of crude oil and natural gas produced, net of production costs	(3,500,790		)		(2,992,447		)		(1,955,555		)
Development costs incurred during the period	2,466,748				1,210,223				1,095,156
Change in timing of estimated future production and other	(309,902		)		464,111				(102,519		)
Change in income taxes	(457,647		)		(1,751,016		)		(433,630		)
Net change	2,137,267				5,115,410				3,675,001
Standardized measure of discounted future net cash flows at December 31	$	18,433,034			$	16,295,767			$	11,180,357

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited)
	The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below.
			Quarter ended
	In thousands, except per share data		March 31			June 30			September 30			December 31
	2014											-2
	Total revenues (1)		$	972,495		$	886,095		$	1,645,328		$	1,297,700
	Gain (loss) on derivative instruments, net (1)		$	(39,674	)	$	(262,524	)	$	473,999		$	387,958
	Income from operations		$	421,317		$	236,394		$	944,897		$	265,228
	Net income		$	226,234		$	103,538		$	533,521		$	114,048
	Net income per share:
	Basic		$	0.61		$	0.28		$	1.45		$	0.31
	Diluted		$	0.61		$	0.28		$	1.44		$	0.31
	2013
	Total revenues (1)(3)		$	702,643		$	1,093,057		$	814,887		$	811,220
	Gain (loss) on derivative instruments, net (1)		$	(84,831	)	$	199,056		$	(203,774	)	$	(102,202	)
	Income from operations		$	270,146		$	573,872		$	328,043		$	273,706
	Net income		$	140,627		$	323,270		$	167,498		$	132,824
	Net income per share:
	Basic		$	0.38		$	0.88		$	0.45		$	0.36
	Diluted		$	0.38		$	0.87		$	0.45		$	0.36
	-1	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
	-2	Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.
	-3	Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively.

Organization_and_Summary_of_Si1

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Company	Description of the Company
	Continental Resources, Inc. (the “Company”) was originally formed in 1967 and is incorporated under the laws of the State of Oklahoma. The Company's principal business is crude oil and natural gas exploration, development and production with properties in the North, South, and East regions of the United States. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes Kansas and all properties south of Kansas and west of the Mississippi River including various plays in the South Central Oklahoma Oil Province (“SCOOP”), Northwest Cana and Arkoma areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations.
	The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 74% of the Company’s crude oil and natural gas production and approximately 83% of its crude oil and natural gas revenues for the year ended December 31, 2014. The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2014, approximately 69% of the Company’s estimated proved reserves were located in the North region. In 2012 and 2013, the Company significantly expanded its activity in the South region with its discovery and announcement of the SCOOP play in Oklahoma. The South region now comprises 26% of the Company's crude oil and natural gas production and 31% of its estimated proved reserves as of December 31, 2014.
	The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2014, crude oil accounted for approximately 70% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 64% of the Company's estimated proved reserves as of December 31, 2014.
Basis of presentation of consolidated financial statements	Basis of presentation of consolidated financial statements
	The consolidated financial statements include the accounts of the Company and its subsidiaries, all of which are 100% owned, after all significant intercompany accounts and transactions have been eliminated upon consolidation.
Stock Split	Stock split
	On August 18, 2014, the Company's Board of Directors declared a 2-for-1 stock split of the Company's common stock to be effected in the form of a stock dividend. The stock dividend was distributed on September 10, 2014 to shareholders of record as of September 3, 2014. All previously reported common stock and earnings per share amounts have been retroactively adjusted in the accompanying financial statements and related notes to reflect the stock split.
Use of Estimates	Use of estimates
	The preparation of financial statements in conformity with accounting principles generally accepted in the United States (“U.S. GAAP”) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure and estimation of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates. The most significant of the estimates and assumptions that affect reported results are the estimates of the Company’s crude oil and natural gas reserves, which are used to compute depreciation, depletion, amortization and impairment of proved crude oil and natural gas properties. In the opinion of management, all adjustments (consisting only of normal recurring adjustments) necessary for a fair presentation in accordance with U.S. GAAP have been included in these consolidated financial statements.
Revenue Recognition	Revenue recognition
	Crude oil and natural gas sales result from interests owned by the Company in crude oil and natural gas properties. Sales of crude oil and natural gas produced from crude oil and natural gas operations are recognized when the product is delivered to the purchaser and title transfers to the purchaser. Payment is generally received one to three months after the sale has occurred. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company’s aggregate imbalance positions at December 31, 2014 and 2013 were not material.
Cash and Cash Equivalents	Cash and cash equivalents
	The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2014, the Company had cash deposits in excess of federally insured amounts of approximately $22.6 million. The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts Receivable	Accounts receivable
	The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material.
Concentration of Credit Risk	Concentration of credit risk
	The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2014, sales to the Company’s two largest purchasers accounted for approximately 14% and 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2014. The Company does not require collateral and does not believe the loss of any single purchaser would materially impact its operating results, as crude oil and natural gas are fungible products with well-established markets and numerous purchasers in the Company’s operating regions.
Inventories	Inventories
	Inventories are stated at the lower of cost or market and consist of the following:
			December 31,
	In thousands		2014			2013
	Tubular goods and equipment		$	15,659		$	11,139
	Crude oil		86,520			43,301
	Total		$	102,179		$	54,440
	Crude oil inventories are valued at the lower of cost or market using the first-in, first-out inventory method. Crude oil inventories consist of the following volumes:
			December 31,
	MBbls		2014		2013
	Crude oil line fill and tank requirements		1,323		370
	Temporarily stored crude oil		596		344
	Total		1,919		714
Crude Oil and Natural Gas Properties	Crude oil and natural gas properties
	The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized.
	Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value.
	Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations.
Service Property and Equipment	Service property and equipment
	Service property and equipment consist primarily of furniture and fixtures, automobiles, machinery and equipment, office equipment, computer equipment and software, and buildings and improvements. Major renewals and replacements are capitalized and stated at cost, while maintenance and repairs are expensed as incurred.
	Depreciation and amortization of service property and equipment are provided in amounts sufficient to expense the cost of depreciable assets to operations over their estimated useful lives using the straight-line method. The estimated useful lives of service property and equipment are as follows:
	Service property and equipment	Useful Lives
		In Years
	Furniture and fixtures	10
	Automobiles	6-May
	Machinery and equipment	20-Oct
	Office equipment, computer equipment and software	10-Mar
	Enterprise resource planning software	25
	Buildings and improvements	Oct-40
Depreciation, Depletion and Amortization	Depreciation, depletion and amortization
	Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset Retirement Obligations	Asset retirement obligations
	The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
Asset Impairment	Asset impairment
	Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter, or when events and circumstances indicate a possible decline in the recoverability of the carrying value of such field. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.
	Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Individually significant non-producing properties, if any, are assessed for impairment on a property-by-property basis and, if the assessment indicates an impairment, a loss is recognized by providing a valuation allowance consistent with the level at which impairment was assessed. For individually insignificant non-producing properties, impairment losses are recognized by amortizing the portion of the properties’ costs which management estimates will not be transferred to proved properties over the lives of the leases based on experience of successful drilling and the average holding period. The Company’s impairment assessments are affected by economic factors such as the results of exploration activities, commodity price outlooks, anticipated drilling programs, remaining lease terms, and potential shifts in business strategy employed by management.
Debt Issuance Costs	Debt issuance costs
	Costs incurred in connection with the execution of the Company’s credit facility and amendments thereto are capitalized and amortized over the term of the facility on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
Derivative Instruments	Derivative instruments
	The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on anticipated settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income under the caption “Gain (loss) on derivative instruments, net.”
Fair Value of Financial Instruments	Fair value of financial instruments
	The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2014 and 2013.
Income Taxes	Income taxes
	Income taxes are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at year-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense.
Earnings Per Share	Earnings per share
	Basic net income per share is computed by dividing net income by the weighted-average number of shares outstanding for the period. Diluted net income per share reflects the potential dilution of non-vested restricted stock awards and stock options, which are calculated using the treasury stock method.
Foreign Currency Transactions and Translations Policy	Foreign currency translation
	In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	Inventories are stated at the lower of cost or market and consist of the following:
			December 31,
	In thousands		2014				2013
	Tubular goods and equipment		$	15,659			$	11,139
	Crude oil		86,520				43,301
	Total		$	102,179			$	54,440
Components of Crude Oil Inventories Volumes	Crude oil inventories consist of the following volumes:
			December 31,
	MBbls		2014			2013
	Crude oil line fill and tank requirements		1,323			370
	Temporarily stored crude oil		596			344
	Total		1,919			714
Schedule of Estimated Useful Lives of Service Property and Equipment	The estimated useful lives of service property and equipment are as follows:
	Service property and equipment	Useful Lives
		In Years
	Furniture and fixtures	10
	Automobiles	6-May
	Machinery and equipment	20-Oct
	Office equipment, computer equipment and software	10-Mar
	Enterprise resource planning software	25
	Buildings and improvements	Oct-40
Summary of Changes in Future Abandonment Liabilities	The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2012 through December 31, 2014:
	In thousands		2014				2013			2012
	Asset retirement obligations at January 1		$	55,787			$	47,171		$	62,625
	Accretion expense		3,366				2,767			3,105
	Revisions		9,916				2,826			(2,871		)
	Plus: Additions for new assets		9,022				6,009			6,679
	Less: Plugging costs and sold assets (1)		(1,383		)		(2,986		)	(22,367		)
	Total asset retirement obligations at December 31		$	76,708			$	55,787		$	47,171
	Less: Current portion of asset retirement obligations at December 31 (2)		1,246				1,434			2,227
	Non-current portion of asset retirement obligations at December 31		$	75,462			$	54,353		$	44,944
	-1	As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion.
	-2	Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income per share for the years ended December 31, 2014, 2013 and 2012. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012. Weighted average shares and net income per share amounts for 2012 and 2013 have been retroactively adjusted to reflect the Company's 2-for-1 stock split occurring in September 2014.
			Year ended December 31,
	In thousands, except per share data		2014				2013			2012
	Income (numerator):
	Net income - basic and diluted		$	977,341			$	764,219		$	739,385
	Weighted average shares (denominator):
	Weighted average shares - basic		368,829				368,150			362,680
	Non-vested restricted stock		1,929				1,548			980
	Stock options		—				—			32
	Weighted average shares - diluted		370,758				369,698			363,692
	Net income per share:
	Basic		$	2.65			$	2.08		$	2.04
	Diluted		$	2.64			$	2.07		$	2.03

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Cash Flow Information [Abstract]
Summary of Supplemental Cash Flow Information	The following table discloses supplemental cash flow information about cash paid for interest and income taxes. Also disclosed is information about investing activities that affects recognized assets and liabilities but does not result in cash receipts or payments.
		Year ended December 31,
	In thousands	2014		2013		2012
	Supplemental cash flow information:
	Cash paid for interest	$	267,384	$	209,815	$	102,043
	Cash paid for income taxes	53,457		29,017		829
	Cash received for income tax refunds	7		174		13,866
	Non-cash investing activities:
	Increase in accrued capital expenditures	290,782		89,482		49,039
	Acquisition of assets through issuance of common stock (Note 11)	—		—		176,563
	Asset retirement obligation additions and revisions, net	18,938		8,835		3,808

Net_Property_and_Equipment_Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2014 and 2013:
		December 31,
	In thousands	2014			2013
	Proved crude oil and natural gas properties	$	17,045,967		$	12,423,878
	Unproved crude oil and natural gas properties	966,080			1,181,268
	Service properties, equipment and other	274,584			236,233
	Total property and equipment	18,286,631			13,841,379
	Accumulated depreciation, depletion and amortization	(4,650,779		)	(3,120,107		)
	Net property and equipment	$	13,635,852		$	10,721,272

Accrued_Liabilities_and_Other_

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2014
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2014 and 2013:
		December 31,
	In thousands	2014		2013
	Prepaid advances from joint interest owners	$	115,687	$	57,196
	Accrued compensation	39,848		41,757
	Accrued production taxes, ad valorem taxes and other non-income taxes	36,550		35,900
	Deferred tax liabilities	145,349		—
	Accrued interest	60,861		61,216
	Current portion of asset retirement obligations	1,246		1,434
	Other	4,965		610
	Accrued liabilities and other	$	404,506	$	198,113

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas
	Natural Gas - Henry Hub					Swaps Weighted Average Price				Floors				Ceilings
												Weighted Average Price			Weighted Average Price
	Period and Type of Contract		MMBtus							Range				Range
	January 2015 - December 2015
	Swaps - Henry Hub		24,500,000			$	4.27
	Collars - Henry Hub		29,200,000							$3.50 - $3.75		$	3.69	$4.89 - $5.48	$	5.04
	January 2016 - December 2016
	Swaps - Henry Hub		63,110,000			$	3.98
Realized and Unrealized Gains and Losses on Derivative Instruments	The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period.
			Year ended December 31,
	In thousands		2014				2013				2012
	Cash received (paid) on derivatives:
	Crude oil fixed price swaps (1)		$	331,591			$	(54,289	)		$	(40,238	)
	Crude oil collars (1)		65,310				(16,867		)		(15,341		)
	Natural gas fixed price swaps		(11,551		)		9,601				9,858
	Cash received (paid) on derivatives, net		385,350				(61,555		)		(45,721		)
	Non-cash gain (loss) on derivatives:
	Crude oil fixed price swaps		84,792				(117,580		)		142,567
	Crude oil collars		1,121				(8,587		)		59,911
	Crude oil written call options		3,981				—				—
	Natural gas fixed price swaps		62,699				(4,029		)		(2,741		)
	Natural gas collars		21,816				—				—
	Non-cash gain (loss) on derivatives, net		174,409				(130,196		)		199,737
	Gain (loss) on derivative instruments, net		$	559,759			$	(191,751	)		$	154,016
	-1	Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. The proceeds include $85 million for contracts with original maturities in November and December of 2014, $337 million for contracts with original maturities in 2015, and $11 million for contracts with original maturities in 2016. Of the proceeds, $373 million relates to crude oil swap liquidations and $60 million relates to crude oil collar liquidations.
Balance sheet offsetting of derivative assets and liabilities	The following tables present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value.
			December 31,
	In thousands		2014				2013
	Commodity derivative assets:
	Gross amounts of recognized assets		$	84,415			$	4,213
	Gross amounts offset on balance sheet		—				(597		)
	Net amounts of assets on balance sheet		84,415				3,616
	Commodity derivative liabilities:
	Gross amounts of recognized liabilities		(4,770		)		(125,709		)
	Gross amounts offset on balance sheet		16				27,345
	Net amounts of liabilities on balance sheet		$	(4,754	)		$	(98,364	)
Schedule Of Derivative Assets Liabilities At Fair Value Net By Balance Sheet Classification Table	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
			December 31,
	In thousands		2014				2013
	Derivative assets		$	52,423			$	3,616
	Noncurrent derivative assets		31,992				—
	Net amounts of assets on balance sheet		84,415				3,616
	Derivative liabilities		(1,645		)		(90,535		)
	Noncurrent derivative liabilities		(3,109		)		(7,829		)
	Net amounts of liabilities on balance sheet		(4,754		)		(98,364		)
	Total derivative assets (liabilities), net		$	79,661			$	(94,748	)
Nymex West Texas Intermediate [Member]
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Crude Oil	At December 31, 2014, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
	Crude Oil - NYMEX WTI				Ceilings
							Weighted Average
	Period and Type of Contract		Bbls		Range		Price
	July 2015 - December 2015
	Written call options - WTI (1)		2,208,000		$95.85 - $103.75		$	98.36
ICE Brent [Member]
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Crude Oil
	Crude Oil - ICE Brent				Ceilings
									Weighted Average
	Period and Type of Contract		Bbls		Range				Price
	July 2015 - December 2015
	Written call options - ICE Brent (1)		368,000		$	107.4			$	107.4
	January 2016 - December 2016
	Written call options - ICE Brent (1)		1,464,000		$	107.7			$	107.7

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Valuation of Financial Instruments by Pricing Levels	The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013.
		Fair value measurements at December 31, 2014 using:
	In thousands	Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps	$	—	$	62,599		$	—	$	62,599
	Collars	—		21,816			—		21,816
	Written call options	—		(4,754		)	—		(4,754		)
	Total	$	—	$	79,661		$	—	$	79,661
		Fair value measurements at December 31, 2013 using:
	In thousands	Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps	$	—	$	(84,893	)	$	—	$	(84,893	)
	Collars	—		(9,855		)	—		(9,855		)
	Total	$	—	$	(94,748	)	$	—	$	(94,748	)
Unobservable inputs used in level 3 fair value measurements
	Unobservable Input	Assumption
	Future production	Future production estimates for each property
	Forward commodity prices	Forward NYMEX swap prices through 2019 (adjusted for differentials), escalating 3% per year thereafter
	Operating and development costs	Estimated costs for the current year, escalating 3% per year thereafter
	Productive life of field	Ranging from 0 to 50 years
	Discount rate	10%
	Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income.
		Year ended December 31,
	In thousands	2014		2013			2012
	Proved property impairments	$	324,302	$	51,805		$	4,332
	Unproved property impairments	292,586		168,703			117,942
	Total	$	616,888	$	220,508		$	122,274
Fair Values of Financial Instruments not Recorded at Fair Value	The following table sets forth the fair values of financial instruments that are not recorded at fair value in the consolidated financial statements.
		December 31, 2014					December 31, 2013
	In thousands	Carrying Amount		Fair Value			Carrying Amount		Fair Value
	Debt:
	Credit facility	$	165,000	$	165,000		$	275,000	$	275,000
	Note payable	16,457		14,900			18,470		16,500
	8.25% Senior Notes due 2019 (1)	—		—			298,305		327,800
	7.375% Senior Notes due 2020	198,850		213,000			198,695		223,700
	7.125% Senior Notes due 2021	400,000		421,000			400,000		450,300
	5% Senior Notes due 2022	2,022,949		1,857,900			2,025,362		2,063,300
	4.5% Senior Notes due 2023	1,500,000		1,372,800			1,500,000		1,519,400
	3.8% Senior Notes due 2024	996,622		868,700			—		—
	4.9% Senior Notes due 2044	698,037		572,400			—		—
	Total debt	$	5,997,915	$	5,485,700		$	4,715,832	$	4,876,000
	(1) These senior notes were redeemed in July 2014. See Note 7. Long-Term Debt for further discussion.

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt consists of the following at December 31, 2014 and 2013:
			December 31,
	In thousands		2014			2013
	Credit facility		$	165,000		$	275,000
	Note payable		16,457			18,470
	8.25% Senior Notes due 2019 (1)		—			298,305
	7.375% Senior Notes due 2020 (2)		198,850			198,695
	7.125% Senior Notes due 2021 (3)		400,000			400,000
	5% Senior Notes due 2022 (4)		2,022,949			2,025,362
	4.5% Senior Notes due 2023 (3)		1,500,000			1,500,000
	3.8% Senior Notes due 2024 (5)		996,622			—
	4.9% Senior Notes due 2044 (6)		698,037			—
	Total debt		5,997,915			4,715,832
	Less: Current portion of long-term debt		2,078			2,011
	Long-term debt, net of current portion		$	5,995,837		$	4,713,821
	-1	The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013. The 2019 Notes were redeemed in July 2014 as discussed further below.
	-2	The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively.
	-3	These notes were sold at par and are recorded at 100% of face value.
	-4	The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively.
	-5	The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014.
	-6	The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014.
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations	The following table summarizes the maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations.
			2020 Notes		2021 Notes	2022 Notes		2023 Notes	2024 Notes	2044 Notes
	Maturity date		Oct 1, 2020		April 1, 2021	Sep 15, 2022		April 15, 2023	June 1, 2024	June 1, 2044
	Interest payment dates		April 1,Oct. 1		April 1, Oct. 1	March 15,  Sept. 15		April 15, Oct. 15	June 1, Dec. 1	June 1, Dec. 1
	Call premium redemption period (1)		1-Oct-15		April 1, 2016	15-Mar-17		—	—	—
	Make-whole redemption period (2)		1-Oct-15		April 1, 2016	15-Mar-17		Jan 15, 2023	Mar 1, 2024	Dec 1, 2043
	Equity offering redemption period (3)		—		—	15-Mar-15		—	—	—
	-1	On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption.
	-2	At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
	-3	At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The items comprising the provision for income taxes are as follows for the periods presented:
			Year ended December 31,
	In thousands		2014			2013			2012
	Current income tax provision:
	United States federal		$	—		$	6,193		$	9,191
	Various states		20			16			1,326
	Total current income tax provision		20			6,209			10,517
	Deferred income tax provision:
	United States federal		527,315			403,002			383,157
	Various states		57,362			39,619			22,137
	Total deferred income tax provision		584,677			442,621			405,294
	Total provision for income taxes		$	584,697		$	448,830		$	415,811
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate
			Year ended December 31,
	In thousands		2014			2013			2012
	Expected income tax expense based on US statutory tax rate of 35%		$	546,713		$	424,567		$	404,319
	State income taxes, net of federal benefit		42,169			25,838			15,213
	Canadian valuation allowance		4,389			—			—
	Effect of differing statutory tax rate in Canada		(1,900		)	—			—
	Other, net		(6,674		)	(1,575		)	(3,721		)
	Provision for income taxes		$	584,697		$	448,830		$	415,811
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and liabilities as of December 31, 2014 and 2013 are as follows:
			December 31,
	In thousands		2014			2013
	Current:
	Deferred tax assets (1)
	Non-cash losses on derivatives		$	—		$	33,029
	Other		3,274			2,288
	Total current deferred tax assets		3,274			35,317
	Deferred tax liabilities
	Non-cash gains on derivatives		(19,293		)	—
	Gain on derivative liquidations		(128,198		)	—
	Other		(1,132		)	(645		)
	Total current deferred tax liabilities		(148,623		)	(645		)
	Net current deferred tax assets (liabilities) (2)		(145,349		)	34,672
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards		60,904			41,791
	Non-cash losses on derivatives		—			2,975
	Alternative minimum tax carryforwards		38,715			38,689
	Equity compensation		22,255			16,961
	Other		10,545			3,259
	Total noncurrent deferred tax assets		132,419			103,675
	Canadian valuation allowance		(4,389		)	—
	Total noncurrent deferred tax assets, net of valuation allowance		128,030			103,675
	Deferred tax liabilities
	Property and equipment		(2,254,343		)	(1,840,331		)
	Non-cash gains on derivatives		(10,976		)	—
	Other		(4,158		)	(156		)
	Total noncurrent deferred tax liabilities		(2,269,477		)	(1,840,487		)
	Net noncurrent deferred tax liabilities		(2,141,447		)	(1,736,812		)
	Net deferred tax liabilities		$	(2,286,796	)	$	(1,702,140	)
	-1	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively.
	-2	The net liability balance at December 31, 2014 is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. The net asset balance at December 31, 2013 is included in the caption "Deferred and prepaid taxes" in the consolidated balance sheets.

Lease_Commitments_Tables

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2014
Leases [Abstract]
Schedule of Minimum Future Rental Commitments Under Operating Leases	At December 31, 2014, the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows:
	In thousands	Total amount
	2015	$	4,953
	2016	3,256
	2017	1,234
	2018	856
	2019	300
	Thereafter	3,468
	Total obligations	$	14,067

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2014
Stock-Based Compensation Expense	The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income, is reflected in the table below for the periods presented.
		Year ended December 31,
	In thousands	2014			2013			2012
	Non-cash equity compensation	$	54,353		$	39,890		$	29,057
Schedule of Stock Option Activity	The following table summarizes stock option activity under the 2000 Plan for the periods presented:
		Outstanding					Exercisable
		Number of		Weighted			Number of			Weighted
		options		average			options			average
				exercise						exercise
				price						price
	Outstanding at December 31, 2011	173,000		$	0.36		173,000			$	0.36
	Exercised	(173,000	)	$	0.36
	Outstanding at December 31, 2012	—		—			—			—
Restricted stock [Member]
Summary of Changes in Non-vested Shares of Restricted Stock	A summary of changes in non-vested restricted shares from December 31, 2011 to December 31, 2014 is presented below.
		Number of		Weighted
		non-vested		average
		shares		grant-date
				fair value
	Non-vested restricted shares at December 31, 2011	2,396,688		$	24.33
	Granted	1,832,056		36.73
	Vested	(889,446	)	22.63
	Forfeited	(80,374	)	29.53
	Non-vested restricted shares at December 31, 2012	3,258,924		$	31.64
	Granted	522,518		48.98
	Vested	(929,618	)	23.65
	Forfeited	(137,512	)	35.96
	Non-vested restricted shares at December 31, 2013	2,714,312		$	37.5
	Granted	1,424,764		61.11
	Vested	(1,007,166	)	35.91
	Forfeited	(453,146	)	44.9
	Non-vested restricted shares at December 31, 2014	2,678,764		$	49.4

Crude_Oil_and_Natural_Gas_Prop1

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities	The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2014, 2013 and 2012.
			Year ended December 31,
	In thousands		2014			2013			2012
	Crude oil and natural gas sales (1)		$	4,203,022		$	3,573,431		$	2,349,500
	Production expenses		(352,472		)	(282,197		)	(195,440		)
	Production taxes and other expenses (1)		(349,760		)	(298,787		)	(198,505		)
	Exploration expenses		(50,067		)	(34,947		)	(23,507		)
	Depreciation, depletion, amortization and accretion		(1,338,351		)	(953,796		)	(683,207		)
	Property impairments		(616,888		)	(220,508		)	(122,274		)
	Income taxes		(559,311		)	(659,783		)	(428,095		)
	Results from crude oil and natural gas producing activities		$	936,173		$	1,123,413		$	698,472
	-1	Natural gas transportation and processing charges totaling $33.3 million and $29.9 million for the years ended December 31, 2013 and 2012, respectively, have been reclassified from "Production taxes and other expenses" to "Crude oil and natural gas sales" to conform to the current year presentation as discussed in Note 1. Organization and Summary of Significant Accounting Policies.
Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities	Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2014, 2013 and 2012 are presented below:
			Year ended December 31,
	In thousands		2014			2013			2012
	Property Acquisition Costs:
	Proved		$	48,917		$	16,604		$	738,415
	Unproved		409,529			546,881			745,601
	Total property acquisition costs		458,446			563,485			1,484,016
	Exploration Costs		863,606			687,767			857,681
	Development Costs		3,670,448			2,549,203			1,975,660
	Total		$	4,992,500		$	3,800,455		$	4,317,357
Schedule of Aggregate Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities	Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2014 and 2013 are as follows:
			December 31,
	In thousands		2014			2013
	Proved crude oil and natural gas properties		$	17,045,967		$	12,423,878
	Unproved crude oil and natural gas properties		966,080			1,181,268
	Total		18,012,047			13,605,146
	Less accumulated depreciation, depletion and amortization		(4,601,864		)	(3,083,180		)
	Net capitalized costs		$	13,410,183		$	10,521,966
Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation	The following table presents the amount of capitalized exploratory drilling costs pending evaluation at December 31 for each of the last three years and changes in those amounts during the years then ended:
			Year ended December 31,
	In thousands		2014			2013			2012
	Balance at January 1		$	152,775		$	92,699		$	128,123
	Additions to capitalized exploratory well costs pending determination of proved reserves		627,853			548,933			485,530
	Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves		(671,618		)	(479,507		)	(520,187		)
	Capitalized exploratory well costs charged to expense		(15,589		)	(9,350		)	(767		)
	Balance at December 31		$	93,421		$	152,775		$	92,699
	Number of gross wells		119			67			46

Supplemental_Crude_Oil_and_Nat1

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Crude Oil and Natural Gas Information [Abstract]
Proved crude oil and natural gas reserves	Proved crude oil and natural gas reserves
	Changes in proved reserves were as follows for the periods presented:
		Crude Oil			Natural Gas			Total
		(MBbls)			(MMcf)			(MBoe)
	Proved reserves as of December 31, 2011	326,133			1,093,832			508,438
	Revisions of previous estimates	33,272			(174,736	)		4,149
	Extensions, discoveries and other additions	166,844			400,848			233,652
	Production	(25,070	)		(63,875	)		(35,716	)
	Sales of minerals in place	(7,165	)		(4,046	)		(7,838	)
	Purchases of minerals in place	67,149			89,061			81,992
	Proved reserves as of December 31, 2012	561,163			1,341,084			784,677
	Revisions of previous estimates	(55,783	)		(241,623	)		(96,054	)
	Extensions, discoveries and other additions	267,009			1,065,870			444,654
	Production	(34,989	)		(87,730	)		(49,610	)
	Sales of minerals in place	—			—			—
	Purchases of minerals in place	388			419			458
	Proved reserves as of December 31, 2013	737,788			2,078,020			1,084,125
	Revisions of previous estimates	(67,151	)		(244,783	)		(107,949	)
	Extensions, discoveries and other additions	239,526			1,206,569			440,621
	Production	(44,530	)		(114,295	)		(63,579	)
	Sales of minerals in place	(123	)		(18,623	)		(3,227	)
	Purchases of minerals in place	850			1,498			1,100
	Proved reserves as of December 31, 2014	866,360			2,908,386			1,351,091
Schedule of proved developed and undeveloped oil and gas reserve quantities	The following reserve information sets forth the estimated quantities of proved developed and proved undeveloped crude oil and natural gas reserves of the Company as of December 31, 2014, 2013 and 2012:
		December 31,
		2014			2013			2012
	Proved Developed Reserves
	Crude oil (MBbl)	342,137			278,630			226,870
	Natural Gas (MMcf)	962,051			768,969			545,499
	Total (MBoe)	502,479			406,792			317,786
	Proved Undeveloped Reserves
	Crude oil (MBbl)	524,223			459,158			334,293
	Natural Gas (MMcf)	1,946,335			1,309,051			795,585
	Total (MBoe)	848,612			677,333			466,891
	Total Proved Reserves
	Crude oil (MBbl)	866,360			737,788			561,163
	Natural Gas (MMcf)	2,908,386			2,078,020			1,341,084
	Total (MBoe)	1,351,091			1,084,125			784,677
Standardized Measure of Discounted Future Net Cash Flows	The following table sets forth the standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves as of December 31, 2014, 2013 and 2012.
		December 31,
	In thousands	2014				2013				2012
	Future cash inflows	$	90,867,459			$	78,646,274			$	54,362,574
	Future production costs	(25,799,221		)		(21,333,460		)		(13,103,469		)
	Future development and abandonment costs	(12,842,174		)		(10,250,789		)		(8,295,130		)
	Future income taxes	(13,800,737		)		(12,447,127		)		(8,500,766		)
	Future net cash flows	38,425,327				34,614,898				24,463,209
	10% annual discount for estimated timing of cash flows	(19,992,293		)		(18,319,131		)		(13,282,852		)
	Standardized measure of discounted future net cash flows	$	18,433,034			$	16,295,767			$	11,180,357
Changes in Standardized Measure of Discounted Future Net Cash Flows	The changes in the aggregate standardized measure of discounted future net cash flows attributable to the Company’s proved crude oil and natural gas reserves are presented below for each of the past three years.
		December 31,
	In thousands	2014				2013				2012
	Standardized measure of discounted future net cash flows at January 1	$	16,295,767			$	11,180,357			$	7,505,356
	Extensions, discoveries and improved recoveries, less related costs	5,516,528				6,613,665				3,724,136
	Revisions of previous quantity estimates	(1,755,366		)		(1,765,300		)		254,493
	Changes in estimated future development and abandonment costs	476,665				1,942,585				(298,148		)
	Purchases (sales) of minerals in place, net	(3,196		)		12,012				1,171,047
	Net change in prices and production costs	(1,925,349		)		263,541				(530,515		)
	Accretion of discount	1,629,576				1,118,036				750,536
	Sales of crude oil and natural gas produced, net of production costs	(3,500,790		)		(2,992,447		)		(1,955,555		)
	Development costs incurred during the period	2,466,748				1,210,223				1,095,156
	Change in timing of estimated future production and other	(309,902		)		464,111				(102,519		)
	Change in income taxes	(457,647		)		(1,751,016		)		(433,630		)
	Net change	2,137,267				5,115,410				3,675,001
	Standardized measure of discounted future net cash flows at December 31	$	18,433,034			$	16,295,767			$	11,180,357

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2014 and 2013 is summarized below.
			Quarter ended
	In thousands, except per share data		March 31			June 30			September 30			December 31
	2014											-2
	Total revenues (1)		$	972,495		$	886,095		$	1,645,328		$	1,297,700
	Gain (loss) on derivative instruments, net (1)		$	(39,674	)	$	(262,524	)	$	473,999		$	387,958
	Income from operations		$	421,317		$	236,394		$	944,897		$	265,228
	Net income		$	226,234		$	103,538		$	533,521		$	114,048
	Net income per share:
	Basic		$	0.61		$	0.28		$	1.45		$	0.31
	Diluted		$	0.61		$	0.28		$	1.44		$	0.31
	2013
	Total revenues (1)(3)		$	702,643		$	1,093,057		$	814,887		$	811,220
	Gain (loss) on derivative instruments, net (1)		$	(84,831	)	$	199,056		$	(203,774	)	$	(102,202	)
	Income from operations		$	270,146		$	573,872		$	328,043		$	273,706
	Net income		$	140,627		$	323,270		$	167,498		$	132,824
	Net income per share:
	Basic		$	0.38		$	0.88		$	0.45		$	0.36
	Diluted		$	0.38		$	0.87		$	0.45		$	0.36
	-1	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
	-2	Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.
	-3	Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively.

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	3 Months Ended				12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Organization And Summary Of Significant Accounting Policies [Line Items]
Reclassified Gas Transportation Charges	$9.10	$8.90	$7.70	$7.60		$33.30	$29.90
Percentage of operations concentrated in geographically areas					74.00%
Percentage Of Revenues Concentrated In Geographically Areas					83.00%
Percentage of estimated proved reserves in north region					69.00%
Percentage of crude oil and natural gas production concentrated in south region					26.00%
Percentage of estimated proved reserves in south region					31.00%
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil					70.00%
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil					85.00%
Cash deposits in excess of federally insured amounts					22.6
Net asset retirement costs	44.4				64.7	44.4
Capitalized debt issue costs, relating to long-term debt	69.5				76.1	69.5
Accumulated amortization, relating to capitalized debt issue costs	28.8				38.1	28.8
Amortization expense related to capitalized debt issuance costs					9.3	8.6	5.6
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil					64.00%
8 1/4% Senior Notes due 2019 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage					8.25%
7 3/8% Senior Notes due 2020 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage					7.38%
7 1/8% Senior Notes due 2021 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage					7.13%
5% Senior Notes due 2022 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage					5.00%
4.5% Senior Notes due 2023 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage					4.50%
Largest Customer [Member] | Oil And Natural Gas [Member] | Sales [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues					14.00%
Second Largest Customer [Member] | Oil And Natural Gas [Member] | Sales [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues					11.00%
Affiliated Entity [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Reclassified Gas Transportation Charges						$4.70	$4.70

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$15,659	$11,139
Crude oil	86,520	43,301
Total	$102,179	$54,440

Organization_and_Summary_of_Si5

Organization and Summary of Significant Accounting Policies - Components of Crude Oil Inventories Volumes (Detail)	Dec. 31, 2014	Dec. 31, 2013
	MBbls	MBbls
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Crude oil line fill requirements, in thousands of barrels	1,323	370
Temporarily stored crude oil, in thousands of barrels	596	344
Total, in thousands of barrels	1,919	714

Organization_and_Summary_of_Si6

Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail)	12 Months Ended
	Dec. 31, 2014
Furniture and Fixtures [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Enterprise Resource Planning Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Minimum [Member] | Automobiles [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years
Minimum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Minimum [Member] | Office Equipment, Computer Equipment and Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	3 years
Minimum [Member] | Buildings And Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum [Member] | Automobiles [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	6 years
Maximum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	20 years
Maximum [Member] | Office Equipment, Computer Equipment and Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum [Member] | Buildings And Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	40 years

Organization_and_Summary_of_Si7

Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1	$55,787,000		$47,171,000		$62,625,000
Accretion expense	3,366,000		2,767,000		3,105,000
Revisions	9,916,000		2,826,000		-2,871,000
Plus: Additions for new assets	9,022,000		6,009,000		6,679,000
Less: Plugging costs and sold assets	-1,383,000	[1]	-2,986,000	[1]	-22,367,000	[1]
Total asset retirement obligations at December 31	76,708,000		55,787,000		47,171,000
Less: Current portion of asset retirement obligations at December 31	1,246,000		1,434,000		2,227,000
Non-current portion of asset retirement obligations at December 31	75,462,000		54,353,000		44,944,000
Asset retirement obligation disposed of					$20,000,000
[1]	As a result of asset dispositions during the year ended December 31, 2012, the Company removed $20.0 million of its previously recognized asset retirement obligations that were assumed by the buyers. See Note 13. Property Acquisitions and Dispositions for further discussion.

Organization_and_Summary_of_Si8

Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) (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
Income (numerator):
Net income - basic and diluted	$114,048	$533,521	$103,538	$226,234	$132,824	$167,498	$323,270	$140,627	$977,341	$764,219	$739,385
Weighted average shares - basic									368,829	368,150	362,680
Non-vested restricted stock									1,929	1,548	980
Stock options									0	0	32
Weighted average shares - diluted									370,758	369,698	363,692
Net income per share:
Basic (in dollars per share)	$0.31	$1.45	$0.28	$0.61	$0.36	$0.45	$0.88	$0.38	$2.65	$2.08	$2.04
Diluted (in dollars per share)	$0.31	$1.44	$0.28	$0.61	$0.36	$0.45	$0.87	$0.38	$2.64	$2.07	$2.03

Supplemental_Cash_Flow_Informa2

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental cash flow information:
Cash paid for interest	$267,384	$209,815	$102,043
Cash paid for income taxes	53,457	29,017	829
Cash received for income tax refunds	7	174	13,866
Non-cash investing activities:
Increase in accrued capital expenditures	290,782	89,482	49,039
Acquisition of assets through issuance of common stock (Note 11)	0	0	176,563
Asset retirement obligation additions and revisions, net	$18,938	$8,835	$3,808

Net_Property_and_Equipment_Sch

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$17,045,967	$12,423,878
Unproved crude oil and natural gas properties	966,080	1,181,268
Service properties, equipment and other	274,584	236,233
Total property and equipment	18,286,631	13,841,379
Accumulated depreciation, depletion and amortization	-4,650,779	-3,120,107
Net property and equipment	$13,635,852	$10,721,272

Accrued_Liabilities_and_Other_1

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners	$115,687	$57,196
Accrued compensation	39,848	41,757
Accrued production taxes, ad valorem taxes and other non-income taxes	36,550	35,900
Deferred tax liabilities	145,349	0
Accrued interest	60,861	61,216
Current portion of asset retirement obligations	1,246	1,434	2,227
Other	4,965	610
Accrued liabilities and other	$404,506	$198,113

Derivative_Instruments_Summary

Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail)	12 Months Ended
	Dec. 31, 2014
	bbl
ICE Brent [Member] | Call Option July 2015 to December 2015 [Member]
Derivative [Line Items]
Volume (Bbls)	368,000
Derivative, Average Price Risk Option Strike Price	107.4
ICE Brent [Member] | Call Option January 2016 to December 2016 [Member]
Derivative [Line Items]
Volume (Bbls)	1,464,000
Derivative, Average Price Risk Option Strike Price	107.7
Nymex West Texas Intermediate [Member] | Call Option July 2015 to December 2015 [Member]
Derivative [Line Items]
Volume (Bbls)	2,208,000
Derivative, Average Price Risk Option Strike Price	98.36
Nymex West Texas Intermediate [Member] | Minimum [Member] | Call Option July 2015 to December 2015 [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	95.85
Nymex West Texas Intermediate [Member] | Maximum [Member] | Call Option July 2015 to December 2015 [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	103.75

Derivative_Instruments_Summary1

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) (Natural Gas [Member])	12 Months Ended
	Dec. 31, 2014
	MMBTU
January 2015 to December 2015 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus	24,500,000
Swaps Weighted Average Price	4.27
January 2015 to December 2015 Collars [Member]
Derivative [Line Items]
Derivative, Average Cap Price	5.04
Natural Gas Production Derivative Volume, MMBtus	29,200,000
Derivative, Average Floor Price	3.69
January 2016 to December 2016 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus	63,110,000
Swaps Weighted Average Price	3.98
Maximum [Member] | January 2015 to December 2015 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	3.75
Derivative, Cap Price	5.48
Minimum [Member] | January 2015 to December 2015 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	3.5
Derivative, Cap Price	4.89

Derivative_Instruments_Realize

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) (USD $)

3 Months Ended

12 Months Ended

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

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

$433,000,000

Cash received (paid) on derivatives:

Cash received (paid) on derivatives, net

385,350,000

-61,555,000

-45,721,000

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

174,409,000

-130,196,000

199,737,000

Gain (loss) on derivative instruments, net

387,958,000

[1]

473,999,000

[1]

-262,524,000

[1]

-39,674,000

[1]

-102,202,000

[1]

-203,774,000

[1]

199,056,000

[1]

-84,831,000

[1]

559,759,000

-191,751,000

154,016,000

November 2014 to December 2014 Swaps [Member]

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

85,000,000

January 2015 to December 2015 Swaps [Member]

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

337,000,000

January 2016 to December 2016 Collars [Member]

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

11,000,000

Fixed Price Swaps [Member] | Crude Oil [Member]

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

373,000,000

Cash received (paid) on derivatives:

Cash received (paid) on derivatives, net

331,591,000

-54,289,000

-40,238,000

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

84,792,000

-117,580,000

142,567,000

Fixed Price Swaps [Member] | Natural Gas [Member]

Cash received (paid) on derivatives:

Cash received (paid) on derivatives, net

-11,551,000

9,601,000

9,858,000

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

62,699,000

-4,029,000

-2,741,000

Collars [Member] | Crude Oil [Member]

Derivatives, Fair Value [Line Items]

Cash Proceeds from Liquidated Derivatives

60,000,000

Cash received (paid) on derivatives:

Cash received (paid) on derivatives, net

65,310,000

-16,867,000

-15,341,000

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

1,121,000

-8,587,000

59,911,000

Collars [Member] | Natural Gas [Member]

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

21,816,000

Call Option [Member] | Crude Oil [Member]

Non-cash gain (loss) on derivatives:

Non-cash gain (loss) on derivatives, net

$3,981,000

[1]

Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2)Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.(3)Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively.

Derivative_Instruments_Derivat

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$84,415	$4,213
Commodity derivative assets, Gross amounts offset on balance sheet	0	-597
Derivative assets, Net amounts of assets on balance sheet	84,415	3,616
Commodity derivative liability, Gross amounts of recognized liabilities	-4,770	-125,709
Commodity derivative liability, Gross amounts offset on balance sheet	16	27,345
Derivative liability, Net amounts of liabilities on balance sheet	($4,754)	($98,364)

Derivative_Instruments_Derivat1

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$52,423	$3,616
Noncurrent derivative assets	31,992	0
Derivative assets, Net amounts of assets on balance sheet	84,415	3,616
Derivative liabilities	-1,645	-90,535
Noncurrent derivative liabilities	-3,109	-7,829
Derivative liability, Net amounts of liabilities on balance sheet	-4,754	-98,364
Total derivative assets (liabilities), net	$79,661	($94,748)

Fair_Value_Measurements_Valuat

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Derivative assets (liabilities):
Derivative assets (liabilities)	$79,661	($94,748)
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 1 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	79,661	-94,748
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	62,599	-84,893
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	21,816	-9,855
Fair Value, Inputs, Level 2 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	-4,754
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	79,661	-94,748
Fair Value [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	62,599	-84,893
Fair Value [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	21,816	-9,855
Fair Value [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	($4,754)

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Measurements [Line Items]
Operating cost escalation assumption used in impairment assessment		3.00%
Discount factor utilized as standardized measure for future net cash flows		10.00%
Impairments of proved properties	$255,000,000	$324,302,000	$51,805,000	$4,332,000
Estimated fair value of proved properties	101,000,000	101,000,000
Unproved Oil And Gas Property Fair Value After Impairment	14,200,000	14,200,000
Impairment of significant unproved property	$84,600,000	$92,400,000
Minimum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)		0 years
Maximum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)		50 years
Forward Commodity Prices [Member]
Fair Value Measurements [Line Items]
Forward commodity price escalation assumption used in impairment assessment	3.00%	3.00%

Fair_Value_Measurements_Proper

Fair Value Measurements - Property Impairments (Detail) (USD $)	3 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Inventory Adjustments	$18,200,000	$18,200,000
Proved property impairments	255,000,000	324,302,000	51,805,000	4,332,000
Unproved property impairments		292,586,000	168,703,000	117,942,000
Total		616,888,000	220,508,000	122,274,000
Buffalo Red River Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		96,900,000
Medicine Pole Hill Units [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		75,900,000
South Region [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		39,700,000
Non-Bakken North Region [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		18,400,000
Emerging Areas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Proved property impairments		$75,200,000

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Feb. 17, 2015	19-May-14	Dec. 31, 2013
8 1/4% Senior Notes due 2019 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2019
Debt instrument, stated interest rate	8.25%
7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2020
Debt instrument, stated interest rate	7.38%
7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2021
Debt instrument, stated interest rate	7.13%
5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2022
Debt instrument, stated interest rate	5.00%
4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2023
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2024
Debt instrument, stated interest rate	3.80%
Senior notes	1,000,000
4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2044
Debt instrument, stated interest rate	4.90%
Senior notes	700,000
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	165,000		605,000	1,010,000	275,000
Note payable	16,457				18,470
Total debt	5,997,915				4,715,832
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member]
Fair Value Measurements [Line Items]
Senior notes	0	[1]			298,305	[1]
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	198,850	[2]			198,695	[2]
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	400,000	[3]			400,000	[3]
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	2,022,949	[4]			2,025,362	[4]
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,500,000	[3]			1,500,000	[3]
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	996,622	[5]
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	698,037	[6]
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	165,000				275,000
Note payable	14,900				16,500
Total debt	5,485,700				4,876,000
Fair Value [Member] | 8 1/4% Senior Notes due 2019 [Member]
Fair Value Measurements [Line Items]
Senior notes	0				327,800
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	213,000				223,700
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	421,000				450,300
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,857,900				2,063,300
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,372,800				1,519,400
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	868,700
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	572,400
[1]	The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013.
[2]	The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively.
[3]	These notes were sold at par and are recorded at 100% of face value.
[4]	The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively.
[5]	The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014.
[6]	The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014.

LongTerm_Debt_LongTerm_Debt_De

Long-Term Debt - Long-Term Debt (Detail) (USD $)	3 Months Ended		12 Months Ended
	Dec. 31, 2014		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Feb. 17, 2015	19-May-14
Debt Instrument [Line Items]
Less: Current portion of long-term debt	($2,078,000)		($2,078,000)		($2,011,000)
Long-term debt, net of current portion	5,995,837,000		5,995,837,000		4,713,821,000
Proceeds from Debt, Net of Issuance Costs	1,680,000,000
Loss on extinguishment of debt			-24,517,000		0		0
8 1/4% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total Redemption Amount	317,500,000		317,500,000
Debt instrument, stated interest rate	8.25%		8.25%
Discounts					1,700,000
Loss on extinguishment of debt			24,517,000
7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.38%		7.38%
Discounts	1,200,000		1,200,000		1,300,000
7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.13%		7.13%
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%		5.00%
Premium	22,900,000		22,900,000		25,400,000
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%		4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	1,000,000,000		1,000,000,000
Debt instrument, stated interest rate	3.80%		3.80%
Discounts	3,400,000		3,400,000
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	700,000,000		700,000,000
Debt instrument, stated interest rate	4.90%		4.90%
Discounts	2,000,000		2,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Senior notes recorded as percentage of face value	100.00%		100.00%
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	165,000,000		165,000,000		275,000,000			605,000,000	1,010,000,000
Note payable	16,457,000		16,457,000		18,470,000
Total debt	5,997,915,000		5,997,915,000		4,715,832,000
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Senior notes	0	[1]	0	[1]	298,305,000	[1]
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior notes	198,850,000	[2]	198,850,000	[2]	198,695,000	[2]
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Senior notes	400,000,000	[3]	400,000,000	[3]	400,000,000	[3]
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	2,022,949,000	[4]	2,022,949,000	[4]	2,025,362,000	[4]
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,500,000,000	[3]	1,500,000,000	[3]	1,500,000,000	[3]
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	996,622,000	[5]	996,622,000	[5]
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$698,037,000	[6]	$698,037,000	[6]
[1]	The carrying amount is net of an unamortized discount of $1.7 million at December 31, 2013.
[2]	The carrying amount is net of unamortized discounts of $1.2 million and $1.3 million at December 31, 2014 and 2013, respectively.
[3]	These notes were sold at par and are recorded at 100% of face value.
[4]	The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively.
[5]	The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014.
[6]	The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014.

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Feb. 17, 2015	19-May-14
Debt Instrument [Line Items]
Aggregate amount of lender commitments on credit facility	$1,750,000,000
Maximum borrowing capacity	4,000,000,000
Line of credit facility, commitment fee percentage, per annum	0.23%
Line of Credit Facility, Covenant Terms	0.65
Proceeds from issuance of Senior Notes	1,681,834,000		1,479,375,000		1,999,000,000
Repayments of Lines of Credit	1,805,000,000		1,290,000,000		1,882,000,000
Debt Instrument Percentage Redeemable	35.00%
Current portion of long-term debt	2,078,000		2,011,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, unused commitments						1,900,000,000
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable	22,000,000
Loan period, in years	10 years
Debt instrument, stated interest rate	3.14%
Debt instrument, maturity date	26-Feb-22
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	15-Apr-23
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	1,000,000,000
Debt instrument, stated interest rate	3.80%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	700,000,000
Debt instrument, stated interest rate	4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	165,000,000		275,000,000			605,000,000	1,010,000,000
Notes Payable	16,457,000		18,470,000
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	2,022,949,000	[1]	2,025,362,000	[1]
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,500,000,000	[2]	1,500,000,000	[2]
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	996,622,000	[3]
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$698,037,000	[4]
[1]	The carrying amount includes an unamortized premium of $22.9 million and $25.4 million at December 31, 2014 and 2013, respectively.
[2]	These notes were sold at par and are recorded at 100% of face value.
[3]	The carrying amount is net of an unamortized discount of $3.4 million at December 31, 2014.
[4]	The carrying amount is net of an unamortized discount of $2.0 million at December 31, 2014.

LongTerm_Debt_Summary_of_Matur

Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods Of Outstanding Senior Note Obligations (Detail)	12 Months Ended
	Dec. 31, 2014
2020 Notes [Member]
Debt Instrument [Line Items]
Maturity date	1-Oct-20
Interest Payment Dates	April 1,Oct. 1
Decreasing call premium redemption period	1-Oct-15	[1]
Make-whole redemption period	1-Oct-15	[2]
2021 Notes [Member]
Debt Instrument [Line Items]
Maturity date	1-Apr-21
Interest Payment Dates	April 1, Oct. 1
Decreasing call premium redemption period	1-Apr-16	[1]
Make-whole redemption period	1-Apr-16	[2]
2022 Notes [Member]
Debt Instrument [Line Items]
Maturity date	15-Sep-22
Interest Payment Dates	March 15,  Sept. 15
Decreasing call premium redemption period	15-Mar-17	[1]
Make-whole redemption period	15-Mar-17	[2]
Redemption using equity offering proceeds	15-Mar-15	[3]
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Maturity date	15-Apr-23
Interest Payment Dates	April 15, Oct. 15
Make-whole redemption period	15-Jan-23	[2]
Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Maturity date	1-Jun-24
Interest Payment Dates	June 1, Dec. 1
Make-whole redemption period	1-Mar-24	[2]
Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Maturity date	1-Jun-44
Interest Payment Dates	June 1, Dec. 1
Make-whole redemption period	1-Dec-43	[2]
[1]	On or after these dates, the Company has the option to redeem all or a portion of its senior notes at the decreasing redemption prices specified in the respective senior note indentures (together, the “Indentures”) plus any accrued and unpaid interest to the date of redemption.
[2]	At any time prior to these dates, the Company has the option to redeem all or a portion of its senior notes at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
[3]	At any time prior to this date, the Company may redeem up to 35% of the principal amount of its 2022 Notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the indenture for the 2022 Notes plus any accrued and unpaid interest to the date of redemption.

Income_Taxes_Provision_for_Inc

Income Taxes - Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Current tax provision, Federal	$0	$6,193	$9,191
Current tax provision, State	20	16	1,326
Total current income tax provision	20	6,209	10,517
Deferred tax provision, Federal	527,315	403,002	383,157
Deferred tax provision, State	57,362	39,619	22,137
Total deferred income tax provision	584,677	442,621	405,294
Provision for income taxes	$584,697	$448,830	$415,811

Income_Taxes_Schedule_of_Provi

Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Expected income tax expense based on US statutory tax rate of 35%	$546,713	$424,567	$404,319
State income taxes, net of federal benefit	42,169	25,838	15,213
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	4,389
Deferred Tax Assets, Valuation Allowance	4,389	0	0
Effect of differing statutory tax rate in Canada	-1,900	0	0
Other, net	-6,674	-1,575	-3,721
Provision for income taxes	$584,697	$448,830	$415,811
Federal statutory income tax rate	35.00%

Income_Taxes_Components_of_Def

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
Income Tax Disclosure [Abstract]
Deferred tax assets, Non-cash losses on derivatives, Current	$0	[1]	$33,029,000	[1]
Deferred tax assets, Other, Current	3,274,000	[1]	2,288,000	[1]
Total current deferred tax assets	3,274,000		35,317,000
Deferred Tax Liabilities, Derivatives	-19,293,000
Deferred Tax Liabilities, Gain on Liquidation of Derivatives	-128,198,000
Deferred tax liabilities, Non-cash gains on derivatives, Current	-1,132,000		-645,000
Deferred Tax Liabilities, Gross, Current	-148,623,000		-645,000
Total current deferred tax liabilities	-145,349,000		34,672,000
Deferred tax assets, Net operating loss carryforwards, Noncurrent	60,904,000		41,791,000
Deferred tax assets, Non-cash losses on derivatives, Noncurrent	0		2,975,000
Deferred tax assets, Alternative minimum tax carryforwards, Noncurrent	38,715,000		38,689,000
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	22,255,000		16,961,000
Deferred tax assets, Other, Noncurrent	10,545,000		3,259,000
Total noncurrent deferred tax assets	132,419,000		103,675,000
Deferred Tax Assets, Valuation Allowance, Noncurrent	-4,389,000
Deferred Tax Assets, Net, Noncurrent	128,030,000		103,675,000
Deferred tax liabilities, Property and equipment, Noncurrent	-2,254,343,000		-1,840,331,000
Deferred Tax Liabilities Unrealized Gains on Derivatives, noncurrent	-10,976,000
Deferred tax liabilities, Non-cash gains on derivatives, Noncurrent	-4,158,000		-156,000
Total noncurrent deferred tax liabilities	-2,269,477,000		-1,840,487,000
Net noncurrent deferred tax liabilities	-2,141,447,000		-1,736,812,000
Net deferred tax liabilities	-2,286,796,000		-1,702,140,000
Income Taxes Receivable	$63,300,000		$9,700,000
[1]	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $63.3 million and $9.7 million for prepaid income taxes at December 31, 2014 and 2013, respectively.

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	$19,000,000
Net operating loss carryforwards, State	1,390,000,000
Alternative minimum tax credit carryforward	0
Deferred Tax Assets, Valuation Allowance	4,389,000	0	0
Oklahoma [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$1,370,000,000

Lease_Commitments_Lease_Commit

Lease Commitments - Lease Commitments (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Lease expenses associated with operating leases	$8,000,000	$3,000,000	$2,200,000
2014	4,953,000
2015	3,256,000
2016	1,234,000
2017	856,000
2018	300,000
Thereafter	3,468,000
Total obligations	$14,067,000

Commitments_and_Contingencies_

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date	$610
Drilling commitments 2015	246
Drilling commitments 2016	212
Drilling commitments 2017	123
Drilling commitments 2018	29
Damages claimed related to contingency matter	165
Legal proceedings recorded as a liability under other noncurrent liabilities	2.9	1.7
Future Drilling Commitments End Date	2018-07
Pipeline Transportation Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, end date	2025
Future commitment, total	969
Future commitment, due in 2015	182
Future commitment, due in 2016	187
Future commitment, due in 2017	181
Future commitment, due in 2018	176
Future commitment, due in 2019	140
Future commitments, thereafter	103
Non-operational Pipeline Transportation Commitments[Member]
Long-term Purchase Commitment [Line Items]
Future commitment, in years	5 years
Future commitment, total	260
Fuel [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, total	96
Future commitment, due in 2015	64
Future commitment, due in 2016	32
Affiliated Entity [Member]
Long-term Purchase Commitment [Line Items]
Contractual Obligation	96
Affiliated Entity [Member] | Pipeline Transportation Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, total	$96

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended			1 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Aug. 31, 2012
					Bbls
Related Party Transaction [Line Items]
Deferred Income Taxes Associated With Acquired Properties			$57,000,000
Asset Retirement Obligations Assumed In Acquisition			600,000
Revenues from transactions with related party		95,128,000	100,405,000	58,892,000
Due from affiliates		13,100,000	12,700,000
Due to Affiliate		300,000	200,000
Expenses from transactions with related party		700,000
Related party transaction, due to related party		1,200,000
Production expenses to affiliates		5,123,000	1,408,000	1,974,000
Total amount paid to related party		58,200,000	48,500,000	32,700,000
Due to affiliates		5,600,000	5,100,000
Amount charged to affiliate for aircraft use		51,000	55,000	112,000
Amount charged to company by affiliate for aircraft use		97,000	51,000	102,000
Issuance of common stock to acquire property, in shares	7.8			7.8
Common Stock, Par or Stated Value Per Share	$0.01	$0.01	$0.01	$0.01
Consideration cost	279,000,000
Purchase price adjustment arising after closing date			500,000
Oil And Natural Gas [Member]
Related Party Transaction [Line Items]
Joint Interest Obligations Assumed In Acquisition			38,000,000
Net book value			177,000,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party				1,900,000
Number of barrels sold to affiliate				21,000
Number of barrels purchased from affiliate			30,000	2,000
Purchases from transactions with related party			3,000,000	200,000
Expenses from transactions with related party		1,800,000
Capitalized costs	5,000,000	5,900,000	5,700,000	5,000,000
Production expenses to affiliates		5,100,000	1,400,000	2,000,000
Total amount paid to related party		1,900,000
Related Party Transaction Transportation Contract Period		5
Crude Oil Pipeline Capacity Per Day					10,000
Related Party Transaction Transportation Charges For Crude Oil Per Barrel					5.25
Contractual Obligation		96,000,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party		800,000	1,300,000	38,500,000
Total amount paid to related party		0		300,000
Due to affiliates		100,000	200,000
Revenues paid to related party		1,700,000	2,300,000	38,300,000
Due from affiliates		200,000	400,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party		34,000	238,000
Total amount received from related party		39,000	379,000
Wheatland Oil Inc. [Member] | Chief Executive Officer [Member]
Related Party Transaction [Line Items]
CEO ownership in related party						75.00%
Wheatland Oil Inc. [Member] | Vice Chairman [Member]
Related Party Transaction [Line Items]
Vice Chairman ownership in related party						25.00%
Wheatland [Member]
Related Party Transaction [Line Items]
Net book value			82,000,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party			$100,400,000	$57,000,000

Stock_Based_Compensation_Assoc

Stock Based Compensation - Associated Compensation Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Non-cash equity compensation	$54,353	$39,890	$29,057

StockBased_Compensation_Additi

Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total intrinsic value of options exercised	$7.60
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date		58.2	49.4	33
Unrecognized compensation expense related to non-vested		$72
Unrecognized compensation expense related to non-vested, period for recognition, in years		1 year 5 months
Restricted stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years		1 year
Restricted stock [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years		3 years
2013 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for issue		19,680,072
2013 Plan [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant		18,104,686

Stock_Based_Compensation_Sched

Stock Based Compensation - Schedule of Stock Option Activity (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of stock options, Outstanding, Beginning of period	173,000
Number of stock options, Outstanding, Exercised	-173,000
Number of stock options, Outstanding, End of period	0
Weighted average exercise price, Outstanding, Beginning of period	$0.36
Weighted average exercise price, Outstanding, Exercised	$0.36
Number of stock options, Exercisable, Beginning of period	173,000
Number of stock options, Exercisable, End of period	0
Weighted average exercise price, Exercisable, Beginning of period	$0.36

Stock_Based_Compensation_Summa

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares, beginning balance	2,714,312	3,258,924	2,396,688
Granted shares	1,424,764	522,518	1,832,056
Vested shares	-1,007,166	-929,618	-889,446
Forfeited shares	-453,146	-137,512	-80,374
Non-vested shares, ending balance	2,678,764	2,714,312	3,258,924
Non-vested, weighted average grant-date fair value, beginning of period	$37.50	$31.64	$24.33
Granted, weighted average grant-date fair value	$61.11	$48.98	$36.73
Vested, weighted average grant-date fair value	$35.91	$23.65	$22.63
Forfeited, weighted average grant-date fair value	$44.90	$35.96	$29.53
Non-vested, weighted average grant-date fair value, end of period	$49.40	$37.50	$31.64

Property_Acquisition_and_Dispo

Property Acquisition and Dispositions - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended			1 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2012	Feb. 29, 2012
					acre	acre
Property Acquisition And Dispositions [Line Items]
Acquired producing properties in cash		$458,446,000	$563,485,000	$1,484,016,000
Acquisitions and disposals proceeds	90,000,000			126,400,000	126,400,000
Recognized pre-tax gain				68,000,000	68,000,000
Asset retirement obligations for disposed properties				8,300,000	8,300,000
Interest Sold	49.90%
Net Acres Sold	44,000
Amount of capital to be funded by partner	270,000,000
Percent of capital funded by partner	50.00%
NORTH DAKOTA
Property Acquisition And Dispositions [Line Items]
Acquired producing properties in cash					663,300,000	276,000,000
Acres acquired				119,000	119,000	23,100
NORTH DAKOTA | Producing Properties [Member]
Property Acquisition And Dispositions [Line Items]
Daily production of acquired producing properties, barrels of oil per day				6,500	6,500	1,000
NORTH DAKOTA | Producing properties [Member]
Property Acquisition And Dispositions [Line Items]
Acquired producing properties in cash					477,100,000	51,700,000
Wyoming [Member]
Property Acquisition And Dispositions [Line Items]
Acquisitions and disposals proceeds						84,400,000
Recognized pre-tax gain						50,100,000
Asset retirement obligations for disposed properties						11,100,000
Oklahoma [Member]
Property Acquisition And Dispositions [Line Items]
Acquisitions and disposals proceeds				15,900,000	15,900,000
Recognized pre-tax gain				15,900,000	15,900,000
Asset retirement obligations for disposed properties				$600,000	$600,000

Property_Transaction_with_Rela

Property Transaction with Related Party - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Dec. 31, 2014
Related Party Transaction [Line Items]
Issuance of common stock to acquire property, in shares	7.8
Common Stock, Par or Stated Value Per Share	$0.01	$0.01	$0.01
Consideration cost	$279
Purchase price adjustment arising after closing date		0.5
Asset Retirement Obligations Assumed In Acquisition		0.6
Deferred Income Taxes Associated With Acquired Properties		57
Wheatland [Member]
Related Party Transaction [Line Items]
Net book value		82
Oil And Natural Gas [Member]
Related Party Transaction [Line Items]
Net book value		177
Joint Interest Obligations Assumed In Acquisition		$38

Crude_Oil_and_Natural_Gas_Prop2

Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) (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]
Crude oil and natural gas sales	$4,203,022	$3,573,431	$2,349,500
Production expenses	-352,472	-282,197	-195,440
Production taxes and other expenses (1)	-349,760	-298,787	-198,505
Exploration Expense	-50,067	-34,947	-23,507
Depreciation, depletion, amortization and accretion	-1,338,351	-953,796	-683,207
Property impairments	-616,888	-220,508	-122,274
Income taxes	-559,311	-659,783	-428,095
Results from crude oil and natural gas producing activities	$936,173	$1,123,413	$698,472

Crude_Oil_and_Natural_Gas_Prop3

Crude Oil and Natural Gas Property Information - Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) (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]
Property Acquisition Costs - Proved	$48,917	$16,604	$738,415
Property Acquisition Costs - Unproved	409,529	546,881	745,601
Total property acquisition costs	458,446	563,485	1,484,016
Exploration Costs	863,606	687,767	857,681
Development Costs	3,670,448	2,549,203	1,975,660
Total	$4,992,500	$3,800,455	$4,317,357

Crude_Oil_and_Natural_Gas_Prop4

Crude Oil and Natural Gas Property Information - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration costs included in asset retirement costs	$1.20	$1.80	$3.30
Development costs included in asset retirement costs	$19.10	$6	$1

Crude_Oil_and_Natural_Gas_Prop5

Crude Oil and Natural Gas Property Information - Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$17,045,967	$12,423,878
Unproved crude oil and natural gas properties	966,080	1,181,268
Total	18,012,047	13,605,146
Less accumulated depreciation, depletion and amortization	-4,601,864	-3,083,180
Net capitalized costs	$13,410,183	$10,521,966

Crude_Oil_and_Natural_Gas_Prop6

Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Well	Well	Well
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$4,500,000
Number Of Wells With Capitalized Exploratory Well Costs Suspended One Year Beyond Completion Of Drilling	1
Suspended Well Costs Incurred	500,000	4,000,000
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	152,775,000	92,699,000	128,123,000
Additions to capitalized exploratory well costs pending determination of proved reserves	627,853,000	548,933,000	485,530,000
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	-671,618,000	-479,507,000	-520,187,000
Capitalized exploratory well costs charged to expense	-15,589,000	-9,350,000	-767,000
Balance at December 31	$93,421,000	$152,775,000	$92,699,000
Number of wells	119	67	46

Supplemental_Crude_Oil_and_Nat2

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MMcf	MMcf	MMcf
Reserve Quantities [Line Items]
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%	99.00%	99.00%
Percent of proved crude oil reserve estimates prepared by external reserve engineers	99.00%
Percent of proved natural gas reserve estimates prepared by external reserve engineers	95.00%
Revisions of previous estimates	53
Revisions of previous estimates	-107,949	-96,054	4,149
Extensions, discoveries and other additions	440,621	444,654	233,652
Discount factor utilized as standardized measure for future net cash flows	10.00%
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	-67,151	-55,783	33,272
Extensions, discoveries and other additions	239,526	267,009	166,844
Weighted average price utilized in computation of future cash inflows	84.54	91.5	86.56
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	-244,783	-241,623	-174,736
Extensions, discoveries and other additions	1,206,569	1,065,870	400,848
Weighted average price utilized in computation of future cash inflows	6.06	5.36		4.31
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	184,000
Extensions, discoveries and other additions	222,000
SCOOP [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions	55,000
Extensions, discoveries and other additions	208,000

Supplemental_Crude_Oil_and_Nat3

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	MMcf	MBoe	MBoe
	MBoe
Reserve Quantities [Line Items]
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%	99.00%	99.00%
Changes in Proved Reserves [Roll Forward]
Revisions of previous estimates	315
Proved reserves at beginning of period, Total	1,084,125	784,677	508,438
Revisions of previous estimates, Total	-107,949	-96,054	4,149
Extensions, discoveries and other additions, Total	440,621	444,654	233,652
Production, Total	-63,579	-49,610	-35,716
Sales of minerals in place, Total	-3,227	0	-7,838
Purchases of minerals in place, Total	1,100	458	81,992
Proved reserves at end of period, Total	1,351,091	1,084,125	784,677
Percent of proved crude oil reserve estimates prepared by external reserve engineers	99.00%
Percent of proved natural gas reserve estimates prepared by external reserve engineers	95.00%
Natural Gas [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period	2,078,020	1,341,084	1,093,832
Revisions of previous estimates	-244,783	-241,623	-174,736
Extensions, discoveries and other additions	1,206,569	1,065,870	400,848
Production	-114,295	-87,730	-63,875
Sales of minerals in place	-18,623	0	-4,046
Purchases of minerals in place	1,498	419	89,061
Proved reserves at end of period	2,908,386	2,078,020	1,341,084
Crude Oil [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period	737,788	561,163	326,133
Revisions of previous estimates	-67,151	-55,783	33,272
Extensions, discoveries and other additions	239,526	267,009	166,844
Production	-44,530	-34,989	-25,070
Sales of minerals in place	-123	0	-7,165
Purchases of minerals in place	850	388	67,149
Proved reserves at end of period	866,360	737,788	561,163

Supplemental_Crude_Oil_and_Nat4

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBbls	MBbls	MBbls	MBbls
Reserve Quantities [Line Items]
Revisions of previous estimates	53
Proved Developed Reserves (MBOE)	502,479	406,792	317,786
Proved Undeveloped Reserve (MBOE)	848,612	677,333	466,891
Total Proved Reserves (MBOE)	1,351,091	1,084,125	784,677
Proved Developed and Undeveloped Reserve, Revision of Previous Estimate (Energy)	105
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	-67,151	-55,783	33,272
Proved Developed Reserves (Volume)	342,137	278,630	226,870
Proved Undeveloped Reserve (Volume)	524,223	459,158	334,293
Total Proved Reserves (Volume)	866,360	737,788	561,163	326,133
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	-244,783	-241,623	-174,736
Proved Developed Reserves (Volume)	962,051	768,969	545,499
Proved Undeveloped Reserve (Volume)	1,946,335	1,309,051	795,585
Total Proved Reserves (Volume)	2,908,386	2,078,020	1,341,084	1,093,832

Supplemental_Crude_Oil_and_Nat5

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$90,867,459	$78,646,274	$54,362,574
Future production costs	-25,799,221	-21,333,460	-13,103,469
Future development and abandonment costs	-12,842,174	-10,250,789	-8,295,130
Future income taxes	-13,800,737	-12,447,127	-8,500,766
Future net cash flows	38,425,327	34,614,898	24,463,209
10% annual discount for estimated timing of cash flows	-19,992,293	-18,319,131	-13,282,852
Standardized measure of discounted future net cash flows	$18,433,034	$16,295,767	$11,180,357	$7,505,356

Supplemental_Crude_Oil_and_Nat6

Supplemental Crude Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at beginning of year	$16,295,767	$11,180,357	$7,505,356
Extensions, discoveries and improved recoveries, less related costs	5,516,528	6,613,665	3,724,136
Revisions of previous quantity estimates	-1,755,366	-1,765,300	254,493
Changes in estimated future development and abandonment costs	476,665	1,942,585	-298,148
Decrease Due to Sales of Minerals in Place	-3,196
Purchases (sales) of minerals in place		12,012	1,171,047
Net change in prices and production costs	-1,925,349	263,541	-530,515
Accretion of discount	1,629,576	1,118,036	750,536
Sales of crude oil and natural gas produced, net of production costs	-3,500,790	-2,992,447	-1,955,555
Development costs incurred during the period	2,466,748	1,210,223	1,095,156
Change in timing of estimated future production and other	-309,902	464,111	-102,519
Change in income taxes	-457,647	-1,751,016	-433,630
Net change	2,137,267	5,115,410	3,675,001
Standardized measure of discounted future net cash flows at end of year	$18,433,034	$16,295,767	$11,180,357

Quarterly_Financial_Data_Sched

Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) (USD $)	3 Months Ended																12 Months Ended
	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
Quarterly Financial Information Disclosure [Abstract]
Cash Proceeds from Liquidated Derivatives	$433,000,000
Cash Proceeds from Liquidated Derivatives, after tax	273,000,000
Cash Proceeds from Liquidated Derivatives, per share	$0.74
Non-recurring Impairment Charges in the Fourth Quarter	340,000,000
Non-recurring Impairment Charges, after tax	214,000,000
Non-recurring Impairment Charges, per share	$0.58
Reclassified Gas Transportation Charges									9,100,000		8,900,000		7,700,000		7,600,000			33,300,000	29,900,000
Total revenues	1,297,700,000	[1]	1,645,328,000	[1]	886,095,000	[1]	972,495,000	[1]	811,220,000	[1]	814,887,000	[1]	1,093,057,000	[1]	702,643,000	[1]	4,801,618,000	3,421,807,000	2,542,587,000
Gain (loss) on derivative instruments, net	387,958,000	[1]	473,999,000	[1]	-262,524,000	[1]	-39,674,000	[1]	-102,202,000	[1]	-203,774,000	[1]	199,056,000	[1]	-84,831,000	[1]	559,759,000	-191,751,000	154,016,000
Income from operations	265,228,000		944,897,000		236,394,000		421,317,000		273,706,000		328,043,000		573,872,000		270,146,000		1,867,836,000	1,445,767,000	1,292,807,000
Net income	$114,048,000		$533,521,000		$103,538,000		$226,234,000		$132,824,000		$167,498,000		$323,270,000		$140,627,000		$977,341,000	$764,219,000	$739,385,000
Net income per share: Basic	$0.31		$1.45		$0.28		$0.61		$0.36		$0.45		$0.88		$0.38		$2.65	$2.08	$2.04
Net income per share: Diluted	$0.31		$1.44		$0.28		$0.61		$0.36		$0.45		$0.87		$0.38		$2.64	$2.07	$2.03
[1]	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2)Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities as discussed in Note 5. Derivative Instruments. The 2014 fourth quarter also includes $340 million of pre-tax non-cash impairment charges ($214 million after tax, or $0.58 per basic and diluted share) as discussed in Note 6. Fair Value Measurements.(3)Total revenues for the quarterly periods of 2013 have been adjusted to conform to the current year presentation of natural gas transportation and processing charges as discussed in Note 1. Organization and Summary of Significant Accounting Policies. Reclassified amounts total $7.6 million, $7.7 million, $8.9 million and $9.1 million for the first, second, third and fourth quarters of 2013, respectively.