Continental Resources Inc (CLR) 10-K 27 Feb 14 2013 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Billions, except Share data, unless otherwise specified	Dec. 31, 2013	Feb. 17, 2014	Jun. 30, 2013
Entity Information [Line Items]	'	'	'
Document Type	'10-K	'	'
Amendment Flag	'false	'	'
Document Period End Date	31-Dec-13	'	'
Document Fiscal Year Focus	'2013	'	'
Document Fiscal Period Focus	'FY	'	'
Trading Symbol	'CLR	'	'
Entity Registrant Name	'CONTINENTAL RESOURCES, INC	'	'
Entity Central Index Key	'0000732834	'	'
Current Fiscal Year End Date	'--12-31	'	'
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	'	185,622,427	'
Entity Public Float	'	'	$4.90

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Current assets:	'	'
Cash and cash equivalents	$28,482	$35,729
Receivables:	'	'
Crude oil and natural gas sales	643,498	468,650
Affiliated parties	13,107	12,410
Joint interest and other, net	349,579	356,111
Derivative assets	3,616	18,389
Inventories	54,440	46,743
Deferred and prepaid taxes	44,337	365
Prepaid expenses and other	10,207	8,386
Total current assets	1,147,266	946,783
Net property and equipment, based on successful efforts method of accounting	10,721,272	8,105,269
Net debt issuance costs and other	72,644	55,726
Noncurrent derivative assets	0	32,231
Total assets	11,941,182	9,140,009
Current liabilities:	'	'
Accounts payable trade	885,289	687,310
Revenues and royalties payable	291,772	261,856
Payables to affiliated parties	5,436	6,069
Accrued liabilities and other	198,113	155,681
Derivative liabilities	90,535	12,999
Current portion of long-term debt	2,011	1,950
Total current liabilities	1,473,156	1,125,865
Long-term debt, net of current portion	4,713,821	3,537,771
Other noncurrent liabilities:	'	'
Deferred income tax liabilities	1,736,812	1,262,576
Asset retirement obligations, net of current portion	54,353	44,944
Noncurrent derivative liabilities	7,829	2,173
Other noncurrent liabilities	2,093	2,981
Total other noncurrent liabilities	1,801,087	1,312,674
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; 185,658,659 shares issued and outstanding at December 31, 2013; 185,604,681 shares issued and outstanding at December 31, 2012	1,857	1,856
Additional paid-in capital	1,252,034	1,226,835
Retained earnings	2,699,227	1,935,008
Total shareholders’ equity	3,953,118	3,163,699
Total liabilities and shareholders’ equity	$11,941,182	$9,140,009

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2013	Dec. 31, 2012
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 value	$0.01	$0.01
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares issued	185,658,659	185,604,681
Common stock, outstanding	185,658,659	185,604,681

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues:	'	'	'
Crude oil and natural gas sales	$3,501,666	$2,315,840	$1,553,629
Crude oil and natural gas sales to affiliates	105,108	63,593	93,790
Gain (loss) on derivative instruments, net	-191,751	154,016	-30,049
Crude oil and natural gas service operations	40,127	39,071	32,419
Total revenues	3,455,150	2,572,520	1,649,789
Operating costs and expenses:	'	'	'
Production expenses	280,789	193,466	135,178
Production and other expenses to affiliates	6,111	6,675	4,632
Production taxes and other expenses	327,427	223,737	143,236
Exploration expenses	34,947	23,507	27,920
Crude oil and natural gas service operations	29,665	32,248	26,735
Depreciation, depletion, amortization and accretion	965,645	692,118	390,899
Property impairments	220,508	122,274	108,458
General and administrative expenses	144,379	121,735	72,817
Gain on sale of assets, net	-88	-136,047	-20,838
Total operating costs and expenses	2,009,383	1,279,713	889,037
Income from operations	1,445,767	1,292,807	760,752
Other income (expense):	'	'	'
Interest expense	-235,275	-140,708	-76,722
Other	2,557	3,097	3,415
Total other income (expense)	-232,718	-137,611	-73,307
Income before income taxes	1,213,049	1,155,196	687,445
Provision for income taxes	448,830	415,811	258,373
Net income	$764,219	$739,385	$429,072
Basic net income per share (in dollars per share)	$4.15	$4.08	$2.42
Diluted net income per share (in dollars per share)	$4.13	$4.07	$2.41

Consolidated_Statements_of_Sha

Consolidated Statements of Shareholders' Equity (USD $)	Total	Common stock	Additional paid-in capital	Retained earnings
In Thousands, except Share data, unless otherwise specified
Balance at Dec. 31, 2010	$1,208,155	$1,704	$439,900	$766,551
Balance, shares at Dec. 31, 2010	'	170,408,652	'	'
Net income	429,072	'	'	429,072
Public offering of common stock	659,232	101	659,131	'
Public offering of common stock, shares	'	10,080,000	'	'
Stock-based compensation	16,567	'	16,567	'
Stock options:	'	'	'	'
Exercised	13	0	13	'
Exercised, shares	'	18,470	'	'
Repurchased and canceled	-150	0	-150	'
Repurchased and canceled, shares	'	-2,495	'	'
Restricted stock:	'	'	'	'
Issued	5	5	'	'
Issued, shares	'	491,315	'	'
Repurchased and canceled	-4,768	-1	-4,767	'
Repurchased and canceled, shares	'	-82,807	'	'
Forfeited, shares	'	-41,447	'	'
Balance at Dec. 31, 2011	2,308,126	1,809	1,110,694	1,195,623
Balance, shares at Dec. 31, 2011	'	180,871,688	'	'
Net income	739,385	'	'	739,385
Common stock issued in exchange for assets	81,528	39	81,489	'
Common stock issued in exchange for assets, shares	'	3,916,157	'	'
Stock-based compensation	30,209	'	30,209	'
Excess tax benefit on stock-based compensation	15,618	'	'	'
Stock options:	'	'	'	'
Exercised	60	'	60	'
Exercised, shares	18,470	86,500	'	'
Repurchased and canceled	-2,951	'	-2,951	'
Repurchased and canceled, shares	'	-32,984	'	'
Restricted stock:	'	'	'	'
Issued	9	9	'	'
Issued, shares	'	916,028	'	'
Repurchased and canceled	-8,285	-1	-8,284	'
Repurchased and canceled, shares	'	-112,521	'	'
Forfeited, shares	'	-40,187	'	'
Balance at Dec. 31, 2012	3,163,699	1,856	1,226,835	1,935,008
Balance, shares at Dec. 31, 2012	185,604,681	185,604,681	'	'
Net income	764,219	'	'	764,219
Stock-based compensation	39,888	'	39,888	'
Stock options:	'	'	'	'
Exercised, shares	86,500	'	'	'
Restricted stock:	'	'	'	'
Issued	3	3	'	'
Issued, shares	'	261,259	'	'
Repurchased and canceled	-14,690	-1	-14,689	'
Repurchased and canceled, shares	'	-138,525	'	'
Forfeited	-1	-1	'	'
Forfeited, shares	'	-68,756	'	'
Balance at Dec. 31, 2013	$3,953,118	$1,857	$1,252,034	$2,699,227
Balance, shares at Dec. 31, 2013	185,658,659	185,658,659	'	'

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Cash flows from operating activities:	'	'	'
Net income	$764,219	$739,385	$429,072
Adjustments to reconcile net income to net cash provided by operating activities:	'	'	'
Depreciation, depletion, amortization and accretion	965,437	694,698	391,844
Property impairments	220,508	122,274	108,458
Non-cash (gain) loss on derivatives, net	130,196	-199,737	-4,057
Stock-based compensation	39,890	29,057	16,572
Provision for deferred income taxes	442,621	405,294	245,203
Excess tax benefit from stock-based compensation	0	-15,618	0
Dry hole costs	9,350	767	7,949
Gain on sale of assets, net	-88	-136,047	-20,838
Other, net	2,037	5,007	3,661
Changes in assets and liabilities:	'	'	'
Accounts receivable	-166,138	-91,791	-294,702
Inventories	-7,697	-7,165	-3,412
Prepaid expenses and other	-11,537	14,381	-3,329
Accounts payable trade	107,250	-8,487	83,907
Revenues and royalties payable	28,401	40,030	88,976
Accrued liabilities and other	44,260	40,309	20,784
Other noncurrent assets and liabilities	-5,414	-292	-2,173
Net cash provided by operating activities	2,563,295	1,632,065	1,067,915
Cash flows from investing activities:	'	'	'
Exploration and development	-3,660,773	-3,493,652	-1,925,577
Purchase of producing crude oil and natural gas properties	-16,604	-570,985	-65,315
Purchase of other property and equipment	-62,054	-53,468	-44,750
Proceeds from sale of assets and other	28,420	214,735	30,928
Net cash used in investing activities	-3,711,011	-3,903,370	-2,004,714
Cash flows from financing activities:	'	'	'
Revolving credit facility borrowings	970,000	2,119,000	493,000
Repayment of revolving credit facility	-1,290,000	-1,882,000	-165,000
Proceeds from issuance of Senior Notes	1,479,375	1,999,000	0
Proceeds from issuance of common stock	0	0	659,736
Proceeds from other debt	0	22,000	0
Repayment of other debt	-1,951	-1,579	0
Debt issuance costs	-2,265	-7,373	-36
Equity issuance costs	0	0	-368
Repurchase of equity grants	-14,690	-11,236	-4,918
Excess tax benefit from stock-based compensation	0	15,618	0
Exercise of stock options	0	60	13
Net cash provided by financing activities	1,140,469	2,253,490	982,427
Net change in cash and cash equivalents	-7,247	-17,815	45,628
Cash and cash equivalents at beginning of period	35,729	53,544	7,916
Cash and cash equivalents at end of period	$28,482	$35,729	$53,544

Organization_and_Summary_of_Si

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2013
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.
	The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 77% of the Company’s crude oil and natural gas production and approximately 86% of its crude oil and natural gas revenues for the year ended December 31, 2013. Additionally, as of December 31, 2013 approximately 76% of the Company’s estimated proved reserves were located in the North region.
	The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2013, crude oil accounted for approximately 71% of the Company’s total production and approximately 87% of its crude oil and natural gas revenues. Crude oil represents approximately 68% of the Company's estimated proved reserves as of December 31, 2013.
	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.
	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, 2013 and 2012 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, 2013, the Company had cash deposits in excess of federally insured amounts of approximately $28.0 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 years ended December 31, 2013, 2012 and 2011, sales to the Company’s largest purchaser accounted for approximately 15%, 21% and 41% of total crude oil and natural gas sales, respectively. Additionally, for the years ended December 31, 2013 and 2012 the Company’s second largest purchaser accounted for approximately 12% and 11%, respectively, of its total crude oil and natural gas sales. The Company's third largest purchaser accounted for approximately 11% of total crude oil and natural gas sales for the year ended December 31, 2013. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2011, 2012 and 2013. 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		2013				2012
	Tubular goods and equipment		$	11,139			$	13,590
	Crude oil		43,301				33,153
	Total		$	54,440			$	46,743
	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		2013			2012
	Crude oil line fill requirements		370			391
	Temporarily stored crude oil		344			211
	Total		714			602
	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. Total capitalized exploratory drilling costs pending the determination of proved reserves were $152.8 million and $92.7 million as of December 31, 2013 and 2012, respectively. As of December 31, 2013, exploratory drilling costs of $3.9 million, representing 3 wells, were suspended one year beyond the completion of drilling and are expected to be fully evaluated in 2014. Of the suspended costs, $0.5 million was incurred in 2013, $1.5 million was incurred in 2012, none in 2011 and $1.9 million was incurred in 2010.
	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, 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 crude oil and natural gas 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, 2011 through December 31, 2013:
	In thousands		2013				2012			2011
	Asset retirement obligations at January 1		$	47,171			$	62,625		$	56,320
	Accretion expense		2,767				3,105			3,163
	Revisions		2,826				(2,871		)	1,947
	Plus: Additions for new assets		6,009				6,679			3,559
	Less: Plugging costs and sold assets (1)		(2,986		)		(22,367		)	(2,364		)
	Total asset retirement obligations at December 31		$	55,787			$	47,171		$	62,625
	Less: Current portion of asset retirement obligations at December 31 (2)		1,434				2,227			2,287
	Non-current portion of asset retirement obligations at December 31		$	54,353			$	44,944		$	60,338
	-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, 2013 and 2012, net property and equipment on the consolidated balance sheets included $44.4 million and $36.6 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. 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.
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 issuance of the 8 1/4% Senior Notes due 2019, the 7 3/8% Senior Notes due 2020, the 7 1/8% Senior Notes due 2021, the 5% Senior Notes due 2022 and the 4 1/2% Senior Notes due 2023 (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 $69.5 million and $55.3 million (net of accumulated amortization of $28.8 million and $20.2 million) relating to its long-term debt at December 31, 2013 and 2012, respectively. The increase in 2013 resulted from the capitalization of costs incurred in connection with the Company’s April 2013 issuance of 4 1/2% Senior Notes due 2023 as discussed in Note 7. Long-Term Debt. For the years ended December 31, 2013, 2012 and 2011, the Company recognized amortization expense associated with capitalized debt issuance costs of $8.6 million, $5.6 million and $3.3 million, respectively, which are reflected in “Interest expense” in the consolidated statements of 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. 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 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 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. The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short term maturity of those instruments. The fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. See Note 5. Derivative Instruments for quantification of the fair value of the Company’s derivative instruments at December 31, 2013 and 2012.
Long-term debt consists of the Company’s Notes, its note payable, and borrowings on its credit facility. The fair values of the Notes are based on quoted market prices. 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 credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities. See Note 6. Fair Value Measurements for quantification of the fair value of the Company’s long-term debt obligations at December 31, 2013 and 2012.
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 as if the awards and options were exercised. 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, 2013, 2012 and 2011. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012.
		Year ended December 31,
In thousands, except per share data		2013				2012			2011
Income (numerator):
Net income - basic and diluted		$	764,219			$	739,385		$	429,072
Weighted average shares (denominator):
Weighted average shares - basic		184,075				181,340			177,590
Non-vested restricted stock		774				490			544
Stock options		—				16			96
Weighted average shares - diluted		184,849				181,846			178,230
Net income per share:
Basic		$	4.15			$	4.08		$	2.42
Diluted		$	4.13			$	4.07		$	2.41
Adoption of new accounting standard
In December 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-11, Balance Sheet (Topic 210)–Disclosures about Offsetting Assets and Liabilities. The new standard requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity’s financial position. The disclosures are required for recognized financial instruments and derivative instruments that are subject to offsetting or are subject to master netting arrangements irrespective of whether they are offset. The disclosure requirements became effective January 1, 2013 and must be applied retrospectively to all periods presented on the balance sheet. The Company adopted the provisions of the new standard on January 1, 2013 and has included the required disclosures in Note 5. Derivative Instruments. Adoption of the new standard required additional footnote disclosures for the Company's derivative instruments and did not have an impact on its financial position, results of operations or cash flows.

Supplemental_Cash_Flow_Informa

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]	'
Supplemental Cash Flow Information	'
	Supplemental Cash Flow Information
	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	2013			2012			2011
	Supplemental cash flow information:
	Cash paid for interest	$	209,815		$	102,043		$	70,088
	Cash paid for income taxes	29,017			829			16,030
	Cash received for income tax refunds	(174		)	(13,866		)	(116		)
	Non-cash investing activities:
	Increase in accrued capital expenditures	89,482			49,039			173,591
	Acquisition of assets through issuance of common stock (Note 14)	—			176,563			—
	Asset retirement obligation additions and revisions, net	8,835			3,808			5,506

Net_Property_and_Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment, Net [Abstract]	'
Net Property and Equipment	'
	Net Property and Equipment
	Net property and equipment includes the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Proved crude oil and natural gas properties	$	12,423,878		$	8,980,505
	Unproved crude oil and natural gas properties		1,181,268			1,073,944
	Service properties, equipment and other		236,233			170,763
	Total property and equipment		13,841,379			10,225,212
	Accumulated depreciation, depletion and amortization		(3,120,107	)		(2,119,943	)
	Net property and equipment	$	10,721,272		$	8,105,269

Accrued_Liabilities_and_Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2013
Accrued Liabilities and Other Liabilities [Abstract]	'
Accrued Liabilities and Other	'
	Accrued Liabilities and Other
	Accrued liabilities and other includes the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013		2012
	Prepaid advances from joint interest owners	$	57,196	$	30,434
	Accrued compensation		41,757		27,797
	Accrued production taxes, ad valorem taxes and other non-income taxes		35,900		33,466
	Accrued income taxes		—		10,455
	Accrued interest		61,216		46,973
	Current portion of asset retirement obligations		1,434		2,227
	Other		610		4,329
	Accrued liabilities and other	$	198,113	$	155,681

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2013
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 income under the caption “Gain (loss) on derivative instruments, net.”
	The Company has utilized 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, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements.
	At December 31, 2013, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
	Crude Oil–NYMEX WTI				Swaps Weighted Average Price
	Period and Type of Contract	Bbls
	January 2014 - December 2014
	Swaps - WTI	10,851,250			$	96.5
					Swaps				Collars
					Weighted
	Crude Oil–ICE Brent	Bbls			Average				Floors								Ceilings
	Period and Type of Contract				Price				Range				Weighted				Range				Weighted
													Average								Average
													Price								Price
	January 2014 - December 2014
	Swaps - ICE Brent	17,028,000			$	103.17
	Collars - ICE Brent	2,190,000							$90.00 - $95.00				$	90.83			$104.70 - $108.85				$	107.13
	January 2015 - December 2015
	Swaps - ICE Brent	2,737,500			$	99.15
	Collars - ICE Brent	730,000							$	95			$	95			$	107.4			$	107.4
	Natural Gas–NYMEX Henry Hub	MMBtus			Swaps
					Weighted
					Average
	Period and Type of Contract				Price
	January 2014 - December 2014
	Swaps - Henry Hub	64,250,000			$	4.19
	January 2015 - March 2015
	Swaps - Henry Hub	1,800,000			$	4.27
	Derivative gains and losses
	The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect the gain or loss 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 during the period.
		Year ended December 31,
	In thousands	2013				2012				2011
	Cash received (paid) on derivatives:
	Crude oil fixed price swaps	$	(54,289	)		$	(40,238	)		$	(14,900	)
	Crude oil collars	(16,867		)		(15,341		)		(56,511		)
	Natural gas fixed price swaps	9,601				9,858				37,305
	Cash paid on derivatives, net	$	(61,555	)		$	(45,721	)		$	(34,106	)
	Non-cash gain (loss) on derivatives:
	Crude oil fixed price swaps	$	(117,580	)		$	142,567			$	(23,486	)
	Crude oil collars	(8,587		)		59,911				42,239
	Natural gas fixed price swaps	(4,029		)		(2,741		)		(14,696		)
	Non-cash gain (loss) on derivatives, net	$	(130,196	)		$	199,737			$	4,057
	Gain (loss) on derivative instruments, net	$	(191,751	)		$	154,016			$	(30,049	)
	Balance sheet offsetting of derivative assets and liabilities
	In December 2011, the FASB issued ASU No. 2011-11, Balance Sheet (Topic 210)-Disclosures about Offsetting Assets and Liabilities, which requires an entity to disclose information about offsetting arrangements to enable financial statement users to understand the effect of netting arrangements on an entity's financial position. The Company adopted the provisions of the new standard on January 1, 2013 as required and has provided the applicable disclosures below with respect to its derivative instruments.
	All of 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, 2013												December 31, 2012
	In thousands	Gross				Gross amounts				Net amounts of				Gross				Gross amounts				Net amounts of
		amounts of				offset on				assets on				amounts of				offset on				assets on
		recognized				balance sheet				balance sheet				recognized				balance sheet				balance sheet
		assets												assets
	Commodity derivative assets	$	4,213			$	(597	)		$	3,616			$	86,506			$	(35,886	)		$	50,620
		December 31, 2013												December 31, 2012
	In thousands	Gross				Gross amounts				Net amounts of				Gross				Gross amounts				Net amounts of
		amounts of				offset on				liabilities on				amounts of				offset on				liabilities on
		recognized				balance sheet				balance sheet				recognized				balance sheet				balance sheet
		liabilities												liabilities
	Commodity derivative liabilities	$	(125,709	)		$	27,345			$	(98,364	)		$	(16,241	)		$	1,069			$	(15,172	)
	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets.
	In thousands	December 31, 2013				December 31, 2012
Derivative assets	$	3,616			$	18,389
Noncurrent derivative assets	—				32,231
Net amounts of assets on balance sheet	3,616				50,620
Derivative liabilities	(90,535		)		(12,999		)
Noncurrent derivative liabilities	(7,829		)		(2,173		)
Net amounts of liabilities on balance sheet	(98,364		)		(15,172		)
Total derivative assets (liabilities), net	$	(94,748	)		$	35,448

Fair_Value_Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2013
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 collar contracts 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, 2013 and 2012.
	In thousands		Fair value measurements at December 31, 2013 using:
	Description		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	)
	In thousands		Fair value measurements at December 31, 2012 using:
	Description		Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps		$	—	$	36,716		$	—	$	36,716
	Collars		—		(1,268		)	—		(1,268		)
	Total		$	—	$	35,448		$	—	$	35,448
	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. 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. 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 2018 (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 $51.8 million for the year ended December 31, 2013. Such impairments primarily reflected fair value adjustments made for certain properties in the Niobrara play in Colorado and Wyoming driven by uneconomic well results. The impaired properties were written down to their estimated fair value totaling approximately $21.2 million.
	Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2013 and 2012, primarily reflecting recurring 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. Additionally, undeveloped leasehold costs on certain properties in the Niobrara play were individually assessed for impairment in the 2013 fourth quarter based on indicators of impairment and were written down to fair value of $14.9 million, which resulted in $8.4 million of impairment charges being recognized in addition to the recurring amortization described above.
	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 income.
			Year ended December 31,
	In thousands		2013		2012			2011
	Proved property impairments		$	51,805	$	4,332		$	16,107
	Unproved property impairments		168,703		117,942			92,351
	Total		$	220,508	$	122,274		$	108,458
	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, 2013					December 31, 2012
	In thousands		Carrying Amount		Fair Value			Carrying Amount		Fair Value
	Debt:
	Credit facility		$	275,000	$	275,000		$	595,000	$	595,000
	Note payable		18,470		16,500			20,421		20,148
	8 1/4% Senior Notes due 2019		298,305		327,800			298,085		339,000
	7 3/8% Senior Notes due 2020		198,695		223,700			198,552		226,833
	7 1/8% Senior Notes due 2021		400,000		450,300			400,000		454,333
	5% Senior Notes due 2022		2,025,362		2,063,300			2,027,663		2,165,833
	4 1/2% Senior Notes due 2023		1,500,000		1,519,400			—		—
	Total debt		$	4,715,832	$	4,876,000		$	3,539,721	$	3,801,147
	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 1/4% Senior Notes due 2019 (“2019 Notes”), the 7 3/8% Senior Notes due 2020 (“2020 Notes”), the 7 1/8% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), and the 4 1/2% Senior Notes due 2023 ("2023 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, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Long-term debt consists of the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Credit facility		$	275,000		$	595,000
	Note payable		18,470			20,421
	8 1/4% Senior Notes due 2019 (1)		298,305			298,085
	7 3/8% Senior Notes due 2020 (2)		198,695			198,552
	7 1/8% Senior Notes due 2021 (3)		400,000			400,000
	5% Senior Notes due 2022 (4)		2,025,362			2,027,663
	4 1/2% Senior Notes due 2023 (3)		1,500,000			—
	Total debt		4,715,832			3,539,721
	Less: Current portion of long-term debt		(2,011		)	(1,950		)
	Long-term debt, net of current portion		$	4,713,821		$	3,537,771
	-1	The carrying amount is net of unamortized discounts of $1.7 million and $1.9 million at December 31, 2013 and 2012, respectively.
	-2	The carrying amount is net of unamortized discounts of $1.3 million and $1.4 million at December 31, 2013 and 2012, 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 $25.4 million and $27.7 million at December 31, 2013 and 2012, respectively.
	Credit facility
	The Company has a credit facility, maturing on July 1, 2015, with aggregate lender commitments totaling $1.5 billion, which can be increased up to $2.5 billion under the terms of the facility. In November 2013, following an upgrade by Standard & Poor’s Rating Services (“S&P”), as permitted by the credit facility terms, the Company provided the lenders under its credit facility notice of its intention to elect an Additional Covenant Period (as defined in the credit facility). The election of an Additional Covenant Period means that the credit facility is not currently subject to a borrowing base. The election was made in order to facilitate the release of collateral consisting of oil and gas properties securing obligations under the credit facility. On December 11, 2013, the Company delivered notice to the credit facility lenders confirming it had satisfied all conditions for releasing the collateral and the release of such collateral became effective as of December 12, 2013. On December 13, 2013, the Company's credit rating was upgraded by Moody's Investor Services, Inc (“Moody’s”). As a result of the second upgrade, the Company is not currently required to: (i) comply with certain reporting requirements; and (ii) maintain a ratio of the present value of oil and gas properties to total funded debt of not less than 1.5 to 1.0, as set forth in the credit facility.
	The Company had $275 million and $595 million of outstanding borrowings on its credit facility at December 31, 2013 and 2012, respectively. Borrowings under the facility at December 31, 2013 bear interest at a rate per annum equal to the London Interbank Offered Rate (LIBOR) for one, two, three or six months, as elected by the Company, plus a margin of 150 basis points, or the lead bank’s reference rate (prime) plus a margin 50 basis points.
	The Company had approximately $1.2 billion of unused commitments (after considering outstanding borrowings and letters of credit) under its credit facility at December 31, 2013 and incurs commitment fees of 0.25% per annum of the daily average amount of unused borrowing availability. The credit agreement contains certain restrictive covenants including a requirement that the Company maintain a current ratio of not less than 1.0 to 1.0 and a ratio of total funded debt to EBITDAX of no greater than 4.0 to 1.0. As defined by the credit facility, the current ratio represents the ratio of current assets to current liabilities, inclusive of available borrowing capacity under the credit facility and exclusive of current balances associated with derivative contracts and asset retirement obligations. EBITDAX represents earnings before interest expense, income taxes, depreciation, depletion, amortization and accretion, property impairments, exploration expenses, non-cash gains and losses resulting from the requirements of accounting for derivatives, and non-cash equity compensation expense. The total funded debt to EBITDAX ratio represents the sum of outstanding borrowings and letters of credit on the credit facility plus the Company’s note payable and senior note obligations, divided by total EBITDAX for the most recent four quarters. The Company was in compliance with these covenants at December 31, 2013.
	Senior notes
	In April 2013, the Company issued $1.5 billion of 4 1/2% Senior Notes due 2023 and received net proceeds of approximately $1.48 billion after deducting the initial purchasers' fees. The Company used the net proceeds from the offering to repay all borrowings then outstanding under its credit facility, which had a balance prior to payoff of approximately $1.04 billion, to fund a portion of its 2013 capital budget, and for general corporate purposes.
	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.
			2019 Notes		2020 Notes	2021 Notes		2022 Notes	2023 Notes
	Maturity date		Oct 1, 2019		Oct 1, 2020	April 1, 2021		Sep 15, 2022	April 15, 2023
	Interest payment dates		April 1, Oct. 1		April 1, Oct. 1	April 1, Oct. 1		March 15, Sept. 15	April 15, Oct. 15
	Call premium redemption period (1)		Oct 1, 2014		Oct 1, 2015	April 1, 2016		March 15, 2017	n/a
	Make-whole redemption period (2)		Oct 1, 2014		Oct 1, 2015	April 1, 2016		March 15, 2017	Jan 15, 2023
	Equity offering redemption period (3)		—		—	April 1, 2014		March 15, 2015	n/a
	-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 specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
	-3	At any time prior to these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption period for the 2019 Notes and 2020 Notes using equity offering proceeds expired on October 1, 2012 and October 1, 2013, respectively.
	The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements.
	The Indentures, excluding the indenture governing the 2023 Notes, contain certain restrictions on the Company’s ability to incur additional debt, pay dividends on common stock, make certain investments, create certain liens on assets, engage in certain transactions with affiliates, transfer or sell certain assets, consolidate or merge, or sell substantially all of the Company’s assets. However, as a result of the increase in credit ratings assigned to the Company's senior unsecured debt and release of credit facility collateral in December 2013 as described above, certain of the restrictive covenants are not currently applicable, including those limiting the Company’s ability to incur additional debt, pay dividends, make certain investments, engage in certain affiliate transactions, and sell certain assets, among others. In the event the Company's credit ratings are reduced below BBB- by S&P or Baa3 by Moody's or collateral is reinstated under the credit facility, such covenants would be restored. The indenture governing the 2023 Notes is less restrictive and contains covenants that, among others, limit the Company's ability to create liens securing certain indebtedness 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, 2013. Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have insignificant assets with no current value and no operations, fully and unconditionally guarantee the senior notes. The Company’s other subsidiary, 20 Broadway Associates LLC, the value of whose assets and operations are minor, does 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 $2.0 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2013.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2013
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		2013			2012			2011
	Current income tax provision:
	Federal		$	6,193		$	9,191		$	12,931
	State		16			1,326			239
	Total current income tax provision		6,209			10,517			13,170
	Deferred income tax provision:
	Federal		403,002			383,157			212,406
	State		39,619			22,137			32,797
	Total deferred income tax provision		442,621			405,294			245,203
	Total provision for income taxes		$	448,830		$	415,811		$	258,373
	The following table reconciles the provision for income taxes with income tax at the Federal statutory rate for the periods presented:
			Year ended December 31,
	In thousands		2013			2012			2011
	Federal income tax provision at statutory rate (35%)		$	424,567		$	404,319		$	240,606
	State income tax provision, net of Federal benefit		25,838			15,213			17,684
	Other, net		(1,575		)	(3,721		)	83
	Provision for income taxes		$	448,830		$	415,811		$	258,373
	The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
			December 31,
	In thousands		2013			2012
	Current:
	Deferred tax assets (1)
	Non-cash losses on derivatives		$	33,029		$	—
	Other		2,288			2,413
	Total current deferred tax assets		35,317			2,413
	Deferred tax liabilities
	Other		645			2,048
	Total current deferred tax liabilities		645			2,048
	Net current deferred tax assets		34,672			365
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards		41,791			40,441
	Non-cash losses on derivatives		2,975			—
	Alternative minimum tax carryforwards		38,689			27,380
	Other		20,220			11,576
	Total noncurrent deferred tax assets		103,675			79,397
	Deferred tax liabilities
	Property and equipment		1,840,331			1,330,551
	Other		156			11,422
	Total noncurrent deferred tax liabilities		1,840,487			1,341,973
	Net noncurrent deferred tax liabilities		1,736,812			1,262,576
	Net deferred tax liabilities (2)		$	1,702,140		$	1,262,211
	-1	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $9.7 million for prepaid income taxes at December 31, 2013, with no such prepayments at December 31, 2012.
	-2	In addition to the 2012 provision for income taxes of $415.8 million, activity during 2012 includes an increase to deferred tax liabilities of $56.6 million related to the acquisition of assets from Wheatland Oil Inc. (see Note 14) and a decrease of $15.6 million related to the excess tax benefits of stock-based compensation.
	As of December 31, 2013, the Company had state net operating loss carryforwards totaling $1.0 billion which will expire beginning in 2017. The carryforwards have expiration periods that vary according to state jurisdiction. 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 jurisdiction and various state 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 2010.

Lease_Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2013
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, 2013, 2012 and 2011 were $3.0 million, $2.2 million and $1.7 million, respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2013 the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows:
		Total amount
	In these years	In thousands
	2014	$	1,954
	2015	432
	2016	346
	2017	255
	2018	151
	Thereafter	182
	Total obligations	$	3,320

Commitments_and_Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2013
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, 2013. The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets.
	Drilling commitments – As of December 31, 2013, the Company had drilling rig contracts with various terms extending through January 2016. 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 key strategic plays. Future commitments as of December 31, 2013 total approximately $110 million, of which $83 million is expected to be incurred in 2014, $26 million in 2015, and less than $1 million in 2016.
	Fracturing and well stimulation service agreement – The Company has an agreement with a third party whereby the third party will provide, on a take-or-pay basis, hydraulic fracturing services and related equipment to service certain of the Company’s properties in North Dakota and Montana. The agreement, which expires in September 2014, requires the Company to pay a fixed rate per day for a minimum number of days per calendar quarter over the term regardless of whether the services are provided. The agreement also stipulates the Company will bear the cost of certain products and materials used. Future commitments remaining as of December 31, 2013 amount to approximately $16 million, which is expected to be incurred through September 2014.
	Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil pipelines in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The commitments, which have 5-year terms extending as far as November 2017, require the Company to pay varying per-barrel transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2013 under the operational crude oil pipeline transportation arrangements amount to approximately $43 million, of which $14 million is expected to be incurred in 2014, $14 million in 2015, $10 million in 2016, and $5 million in 2017.
	The Company has also entered into a commitment to guarantee pipeline access capacity on an operational natural gas pipeline system to move a portion of its North region natural gas production to market. The commitment, which has a 10-year term ending in October 2023, requires the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments under the arrangement amount to approximately $24 million as of December 31, 2013, which is expected to be incurred ratably over its 10-year term.
	Further, the Company is a party to additional 5-year firm transportation commitments for future crude oil pipeline projects being constructed or considered for development that are not yet operational. Such projects require the granting of regulatory approvals or otherwise require significant additional construction efforts by our counterparties before being completed. Future commitments under the non-operational arrangements total approximately $1.0 billion at December 31, 2013, which includes approximately $96 million subject to a joint tariff arrangement between an unaffiliated party and an affiliate controlled by the Company's principal shareholder as discussed in Note 11. Related Party Transactions. These commitments represent aggregate transportation charges expected to be incurred over the 5-year terms of the arrangements assuming the proposed pipeline projects are completed and become 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 these non-operational arrangements 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. Although timing is uncertain, operators have indicated that certain pipeline projects may become operational in the fourth quarter of 2014, which would obligate the Company for transportation charges totaling $36 million in the 2014 fourth quarter, $143 million per year in years 2015 through 2018, and $106 million in 2019 associated with those projects.
	Rail transportation commitments – The Company has entered into firm transportation commitments to guarantee capacity on rail transportation facilities in order to reduce the impact of possible production curtailments that may arise due to limited transportation capacity. The rail commitments have various terms extending through June 2014 and require the Company to pay varying per-barrel transportation charges regardless of the amount of rail capacity used. Future commitments remaining as of December 31, 2013 under the rail transportation arrangements amount to approximately $10 million, which is expected to be incurred through June 2014.
	The Company’s pipeline and rail transportation 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.
	Cost sharing commitment – The Company has entered into an arrangement to share certain costs associated with a local utility company's construction and installation of electrical infrastructure that will provide service to parts of North Dakota where the Company operates. This arrangement extends through January 2016 and requires the Company to make scheduled periodic payments based on the projected total cost of the project and the progress of construction. Future commitments under the arrangement as of December 31, 2013 total approximately $25 million, of which $15 million is expected to be incurred in 2014, $8 million in 2015, and $2 million 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. 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, 2013 and 2012, the Company has recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $1.7 million and $2.4 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, 2013
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, 2013, 2012, and 2011, these sales amounted to $105.1 million, $61.7 million, and $53.5 million, respectively, and are included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of income. At December 31, 2013 and 2012, $12.7 million and $11.7 million, respectively, was due to the Company from these affiliates, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets.
	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 years ended December 31, 2012, and 2011, crude oil sales to the affiliate totaled 21,000 barrels and 435,000 barrels, respectively, generating sales proceeds of $1.9 million and $41.7 million, respectively. There were no crude oil sales to the affiliate in 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, with no purchases being made from the affiliate in 2011. The Company incurred $2.2 million, $2.7 million, and $1.4 million in transportation and gathering expenses in 2013, 2012, and 2011, respectively, associated with these transactions. At both December 31, 2013 and 2012, $0.2 million was due from the Company to the affiliate associated with these transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.
	The Company contracts for field services such as compression and drilling rig services and purchases residue fuel gas and reclaimed crude oil from certain affiliates. The Company capitalized costs of $5.7 million, $5.0 million and $4.1 million in 2013, 2012, and 2011, respectively, associated with drilling rig services provided by an affiliate. Production and other expenses attributable to these affiliate transactions were $1.4 million, $2.0 million and $4.6 million for the years ended December 31, 2013, 2012, and 2011, respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $48.5 million, $32.7 million and $30.8 million for the years ended December 31, 2013, 2012, and 2011, respectively. Under a contract for natural gas sales to an affiliate, the Company incurred gathering and treatment fees which amounted to $4.7 million in 2013, $4.7 million in 2012 and $4.6 million in 2011. At December 31, 2013 and 2012, $5.1 million and $5.6 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.
	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 $2.3 million, $38.3 million, and $46.8 million and received payments from these affiliates of $1.3 million, $38.5 million, and $67.5 million during the years ended December 31, 2013, 2012, and 2011, respectively, relating to the operations of the respective properties. The Company also paid to these affiliates $277,000 in 2012 and $4,900 in 2011 for their share of proceeds from undeveloped leasehold sales, with no such payments in 2013. At December 31, 2013 and 2012, $0.4 million and $0.7 million was due from these affiliates and approximately $0.2 million and $0.3 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 and $1.0 million for the years ended December 31, 2012 and 2011, respectively.
	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 2013, 2012, and 2011, the Company charged affiliates approximately $55,000, $112,000, and $235,000, respectively, for use of its corporate aircraft, crews and fuel and training costs and received $379,000 from the affiliate in 2013 for certain current and prior year charges. The Company was charged $51,000, $102,000, and $88,000, respectively, by affiliates for use of their aircraft and crews during 2013, 2012, and 2011 and paid $238,000 to the affiliates in 2013 for certain current and prior year charges.
	In September 2012, the Company entered into 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 pipeline projects being developed by an affiliated party and an unaffiliated party that are not yet operational. The pipeline projects require additional construction efforts by those parties before being completed. The commitments require the Company to pay joint tariff transportation charges of $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, 2013, representing aggregate joint tariff transportation charges expected to be incurred over the 5-year term assuming the pipeline projects are completed and become operational. The commitments under this arrangement are not recorded in the accompanying consolidated balance sheets.
	In August 2012, the Company acquired the assets of Wheatland Oil Inc. Wheatland is owned 75% by 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. See Note 14. Property Transaction with Related Party for further discussion.

StockBased_Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2013
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 income, is reflected in the table below for the periods presented.
		Year ended December 31,
	In thousands	2013			2012			2011
	Non-cash equity compensation	$	39,890		$	29,057		$	16,572
	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, 2010	104,970		$	0.71		104,970			$	0.71
	Exercised	(18,470	)	$	0.71
	Outstanding at December 31, 2011	86,500		$	0.71		86,500			$	0.71
	Exercised	(86,500	)	$	0.71
	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 years ended December 31, 2012 and 2011 was $7.6 million and $1.1 million, respectively.
	Restricted stock
	In May 2013, the Company's shareholders, upon recommendation by the Board of Directors, approved the adoption of the Company's 2013 Plan. The 2013 Plan is a broad-based incentive plan that allows the Company to use, if desired, a variety of equity compensation alternatives in structuring compensation arrangements for the Company's officers, directors and select employees. Effective May 23, 2013, 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.
	The maximum number of shares of common stock available for issuance under the 2013 Plan is 9,840,036 shares, which includes (i) 7,500,000 new shares authorized under the 2013 Plan, (ii) 1,840,036 shares that remained available for issuance under the 2005 Plan as of March 27, 2013 that have been transferred from the 2005 Plan to the 2013 Plan, and (iii) up to 500,000 shares available for issuance under the 2013 Plan to the extent such shares are forfeited or withheld for payment of income taxes related to existing awards outstanding under the 2005 Plan. As of December 31, 2013, the Company had a maximum of 9,813,989 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, 2010 to December 31, 2013 is presented below:
		Number of		Weighted
		non-vested		average
		shares		grant-date
				fair value
	Non-vested restricted shares at December 31, 2010	1,108,077		$	35.72
	Granted	491,315		63.59
	Vested	(359,601	)	29.95
	Forfeited	(41,447	)	41.93
	Non-vested restricted shares at December 31, 2011	1,198,344		$	48.66
	Granted	916,028		73.46
	Vested	(444,723	)	45.25
	Forfeited	(40,187	)	59.05
	Non-vested restricted shares at December 31, 2012	1,629,462		$	63.28
	Granted	261,259		97.95
	Vested	(464,809	)	47.3
	Forfeited	(68,756	)	71.91
	Non-vested restricted shares at December 31, 2013	1,357,156		$	74.99
	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 2013, 2012 and 2011 at the vesting date was $49.4 million, $33.0 million and $19.9 million, respectively. As of December 31, 2013, there was approximately $55 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 1.5 years.

Property_Acquisitions_and_Disp

Property Acquisitions and Dispositions	12 Months Ended
	Dec. 31, 2013
Extractive Industries [Abstract]	'
Property Acquisitions and Dispositions	'
	Property Acquisitions and Dispositions
	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 14. Property Transaction with Related Party 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.
	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 transaction excluded a portion of the Company’s non-producing leasehold acreage in the East region, which was retained by the Company for future exploration and development opportunities. The transaction also allowed for the Company to retain an overriding royalty interest in certain of the disposed properties as well as rights to drill in potential unproven deeper formations that may exist below the disposed properties. 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.
	During 2011, the Company assigned certain non-strategic properties in Michigan, North Dakota, and Montana to third parties for total proceeds of $30.2 million. In connection with the transactions, the Company recognized pre-tax gains totaling $21.4 million. Substantially all of the properties disposed of in 2011 consisted of undeveloped leasehold acreage with no proved reserves and no production or revenues.
	The gains on the above dispositions are included in the caption “Gain on sale of assets, net” in the consolidated statements of income.

Property_Transaction_with_Rela

Property Transaction with Related Party	12 Months Ended
	Dec. 31, 2013
Property Transaction With Related Party [Abstract]	'
Property Transaction with Related Party	'
	Property Transaction with Related Party
	In March 2012, the Company entered into a Reorganization and Purchase and Sale Agreement (the “Agreement”) with Wheatland Oil Inc. ("Wheatland") and the shareholders of Wheatland. Wheatland is owned 75% by 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. The Agreement provided for the acquisition by the Company, through the issuance of shares of the Company’s common stock, of all of Wheatland’s right, title and interest in and to certain crude oil and natural gas properties and related assets, in which the Company also owned an interest, in the states of Mississippi, Montana, North Dakota and Oklahoma and the assumption of certain liabilities related thereto.
	The Wheatland transaction was consummated and closed on August 13, 2012, with an effective date of January 1, 2012. At closing, the Company issued an aggregate of approximately 3.9 million shares of its common stock, par value $0.01 per share, to the shareholders of Wheatland in accordance with the terms of the Agreement. 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 Agreement.
	For accounting purposes, the 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. For the year ended December 31, 2012, the acquired Wheatland properties comprised approximately 484 MBoe of the Company’s crude oil and natural gas production and approximately $38 million of its crude oil and natural gas revenues.

Crude_Oil_and_Natural_Gas_Prop

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'
Crude Oil and Natural Gas Property Information	'
	Crude Oil and Natural Gas Property Information
	The following table sets forth the Company’s results of operations from crude oil and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011.
		Year ended December 31,
	In thousands	2013			2012			2011
	Crude oil and natural gas sales	$	3,606,774		$	2,379,433		$	1,647,419
	Production expenses	(282,197		)	(195,440		)	(138,236		)
	Production taxes and other expenses	(332,130		)	(228,438		)	(144,810		)
	Exploration expenses	(34,947		)	(23,507		)	(27,920		)
	Depreciation, depletion, amortization and accretion	(953,796		)	(683,207		)	(384,301		)
	Property impairments	(220,508		)	(122,274		)	(108,458		)
	Income taxes	(659,783		)	(428,095		)	$	(321,447	)
	Results from crude oil and natural gas producing activities	$	1,123,413		$	698,472		$	522,247
	Costs incurred in crude oil and natural gas activities
	Costs incurred, both capitalized and expensed, in connection with the Company’s crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2013, 2012 and 2011 are presented below:
		Year ended December 31,
	In thousands	2013			2012			2011
	Property Acquisition Costs:
	Proved	$	16,604		$	738,415		$	65,315
	Unproved	546,881			745,601			183,247
	Total property acquisition costs	563,485			1,484,016			248,562
	Exploration Costs	687,767			857,681			734,797
	Development Costs	2,549,203			1,975,660			1,178,136
	Total	$	3,800,455		$	4,317,357		$	2,161,495
	Exploration costs above include asset retirement costs of $1.8 million, $3.3 million and $1.7 million and development costs above include asset retirement costs of $6.0 million, $1.0 million and $3.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.
	Aggregate capitalized costs
	Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2013 and 2012 are as follows:
		December 31,
	In thousands	2013			2012
	Proved crude oil and natural gas properties	$	12,423,878		$	8,980,505
	Unproved crude oil and natural gas properties	1,181,268			1,073,944
	Total	13,605,146			10,054,449
	Less accumulated depreciation, depletion and amortization	(3,083,180		)	(2,090,845		)
	Net capitalized costs	$	10,521,966		$	7,963,604
	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 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	2013			2012			2011
	Balance at January 1	$	92,699		$	128,123		$	92,806
	Additions to capitalized exploratory well costs pending determination of proved reserves	548,933			485,530			500,046
	Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(479,507		)	(520,187		)	(456,780		)
	Capitalized exploratory well costs charged to expense	(9,350		)	(767		)	(7,949		)
	Balance at December 31	$	152,775		$	92,699		$	128,123
	Number of gross wells	67			46			56

Supplemental_Crude_Oil_and_Nat

Supplemental Crude Oil and Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2013
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 96% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2013, 2012, and 2011, respectively. Properties comprising 99% of proved crude oil reserves and 94% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2013. Remaining reserve estimates were prepared by the Company’s internal technical staff. All reserves stated herein are located in the United States.
	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, 2013, 2012 and 2011 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, 2013, 2012 and 2011 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, 2010	224,784			839,568			364,712
	Revisions of previous estimates	28,607			(158,219	)		2,237
	Extensions, discoveries and other additions	87,465			447,098			161,981
	Production	(16,469	)		(36,671	)		(22,581	)
	Sales of minerals in place	—			—			—
	Purchases of minerals in place	1,746			2,056			2,089
	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. 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 for both of the years ended December 31, 2011 and 2012 were due to better than anticipated production performance, with 2011 revisions also being positively impacted by higher average commodity prices throughout 2011 as compared to 2010. Downward revisions to natural gas reserves for both of the years ended December 31, 2011 and 2012 were due to the removal of proved undeveloped ("PUD") reserves for certain dry gas properties not expected to be developed given the pricing environment for natural gas.
	Revisions for the year ended December 31, 2013 primarily represent the removal of PUD reserves resulting from a decision in 2013 to allocate a greater focus of the Company's 5-year growth plan to drilling programs in higher rates-of-return crude oil and liquids-rich natural gas areas of the Bakken and SCOOP while continuing to build on the early success in the Company's development of the Lower Three Forks reservoirs in the Bakken. Another contributing factor is the Company's increased focus 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 to maximize rates of return. These factors contributed to the removal of 42 MMBo and 235 Bcf (81 MMBoe) of PUD reserves in 2013.
	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 and strong production growth in the Bakken field. Proved reserve additions in the Bakken totaled 227 MMBo and 293 Bcf (276 MMBoe) for the year ended December 31, 2013. Additionally, 2013 extensions and discoveries were significantly impacted by successful drilling results in the emerging SCOOP play, resulting in 36 MMBo and 730 Bcf (158 MMBoe) of proved reserve additions during the year. Significant progress continued to be made in 2013 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. During the year ended December 31, 2012, the Company disposed of certain non-strategic properties in Oklahoma, Wyoming, and the East region. See Note 13. Property Acquisitions and Dispositions for further discussion of the Company’s 2012 dispositions.
	Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. Purchases for the year ended December 31, 2012 primarily reflected the Company’s acquisitions of properties in the Bakken play of North Dakota during the year. See Note 13. Property Acquisitions and Dispositions and Note 14. Property Transaction with Related Party for further discussion of the Company’s 2012 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, 2013, 2012 and 2011:
		December 31,
		2013			2012			2011
	Proved Developed Reserves
	Crude oil (MBbl)	278,630			226,870			145,024
	Natural Gas (MMcf)	768,969			545,499			361,265
	Total (MBoe)	406,792			317,786			205,235
	Proved Undeveloped Reserves
	Crude oil (MBbl)	459,158			334,293			181,109
	Natural Gas (MMcf)	1,309,051			795,585			732,567
	Total (MBoe)	677,333			466,891			303,203
	Total Proved Reserves
	Crude oil (MBbl)	737,788			561,163			326,133
	Natural Gas (MMcf)	2,078,020			1,341,084			1,093,832
	Total (MBoe)	1,084,125			784,677			508,438
	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, 2013, 2012 and 2011.
		December 31,
	In thousands	2013				2012				2011
	Future cash inflows	$	78,646,274			$	54,362,574			$	35,042,916
	Future production costs	(21,333,460		)		(13,103,469		)		(7,495,552		)
	Future development and abandonment costs	(10,250,789		)		(8,295,130		)		(5,073,043		)
	Future income taxes	(12,447,127		)		(8,500,766		)		(5,956,615		)
	Future net cash flows	34,614,898				24,463,209				16,517,706
	10% annual discount for estimated timing of cash flows	(18,319,131		)		(13,282,852		)		(9,012,350		)
	Standardized measure of discounted future net cash flows	$	16,295,767			$	11,180,357			$	7,505,356
The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $91.50, $86.56, and $88.71 per barrel at December 31, 2013, 2012 and 2011, respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $5.36, $4.31, and $5.59 per Mcf at December 31, 2013, 2012 and 2011, 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	2013				2012				2011
Standardized measure of discounted future net cash flows at January 1	$	11,180,357			$	7,505,356			$	3,785,322
Extensions, discoveries and improved recoveries, less related costs	6,613,665				3,724,136				2,276,355
Revisions of previous quantity estimates	(1,765,300		)		254,493				133,990
Changes in estimated future development and abandonment costs	1,942,585				(298,148		)		(70,219		)
Purchases (sales) of minerals in place, net	12,012				1,171,047				56,246
Net change in prices and production costs	263,541				(530,515		)		1,855,532
Accretion of discount	1,118,036				750,536				378,532
Sales of crude oil and natural gas produced, net of production costs	(2,992,447		)		(1,955,555		)		(1,364,373		)
Development costs incurred during the period	1,210,223				1,095,156				528,737
Change in timing of estimated future production and other	464,111				(102,519		)		773,279
Change in income taxes	(1,751,016		)		(433,630		)		(848,045		)
Net change	5,115,410				3,675,001				3,720,034
Standardized measure of discounted future net cash flows at December 31	$	16,295,767			$	11,180,357			$	7,505,356

Quarterly_Financial_Data_Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Quarterly Financial Data (Unaudited)	'
	Quarterly Financial Data (Unaudited)
	The Company’s unaudited quarterly financial data for 2013 and 2012 is summarized below.
			Quarter ended
	In thousands, except per share data		March 31			June 30		September 30			December 31
	2013
	Total revenues (1)		$	710,229		$	1,100,752	$	823,835		$	820,334
	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		$	0.76		$	1.76	$	0.91		$	0.72
	Diluted		$	0.76		$	1.75	$	0.91		$	0.72
	2012
	Total revenues (1)		$	395,100		$	1,004,719	$	483,729		$	688,972
	Gain (loss) on derivative instruments, net (1)		$	(169,057	)	$	471,728	$	(158,294	)	$	9,639
	Income from operations		$	135,591		$	686,474	$	105,522		$	365,220
	Net income		$	69,094		$	405,684	$	44,096		$	220,511
	Net income per share:
	Basic		$	0.38		$	2.26	$	0.24		$	1.2
	Diluted		$	0.38		$	2.25	$	0.24		$	1.19
	-1	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of 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.

Organization_and_Summary_of_Si1

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2013
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.
	The Company’s operations are geographically concentrated in the North region, with that region comprising approximately 77% of the Company’s crude oil and natural gas production and approximately 86% of its crude oil and natural gas revenues for the year ended December 31, 2013. Additionally, as of December 31, 2013 approximately 76% of the Company’s estimated proved reserves were located in the North region.
	The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2013, crude oil accounted for approximately 71% of the Company’s total production and approximately 87% of its crude oil and natural gas revenues.
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.
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, 2013 and 2012 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.
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 years ended December 31, 2013, 2012 and 2011, sales to the Company’s largest purchaser accounted for approximately 15%, 21% and 41% of total crude oil and natural gas sales, respectively. Additionally, for the years ended December 31, 2013 and 2012 the Company’s second largest purchaser accounted for approximately 12% and 11%, respectively, of its total crude oil and natural gas sales. The Company's third largest purchaser accounted for approximately 11% of total crude oil and natural gas sales for the year ended December 31, 2013. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2011, 2012 and 2013. 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		2013			2012
	Tubular goods and equipment		$	11,139		$	13,590
	Crude oil		43,301			33,153
	Total		$	54,440		$	46,743
	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		2013		2012
	Crude oil line fill requirements		370		391
	Temporarily stored crude oil		344		211
	Total		714		602
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. Total capitalized exploratory drilling costs pending the determination of proved reserves were $152.8 million and $92.7 million as of December 31, 2013 and 2012, respectively. As of December 31, 2013, exploratory drilling costs of $3.9 million, representing 3 wells, were suspended one year beyond the completion of drilling and are expected to be fully evaluated in 2014. Of the suspended costs, $0.5 million was incurred in 2013, $1.5 million was incurred in 2012, none in 2011 and $1.9 million was incurred in 2010.
	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, 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 crude oil and natural gas 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. 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.
	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.
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. 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 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 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. The carrying values of cash, trade receivables and trade payables are considered to be representative of their respective fair values due to the short term maturity of those instruments. The fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars, volatility, the risk-free interest rate, and the time to expiration. See Note 5. Derivative Instruments for quantification of the fair value of the Company’s derivative instruments at December 31, 2013 and 2012.
	Long-term debt consists of the Company’s Notes, its note payable, and borrowings on its credit facility. The fair values of the Notes are based on quoted market prices. 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 credit facility borrowings approximates carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities. See Note 6. Fair Value Measurements for quantification of the fair value of the Company’s long-term debt obligations at December 31, 2013 and 2012.
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 as if the awards and options were exercised.

Organization_and_Summary_of_Si2

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2013
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		2013				2012
	Tubular goods and equipment		$	11,139			$	13,590
	Crude oil		43,301				33,153
	Total		$	54,440			$	46,743
Components of Crude Oil Inventories Volumes	'
	Crude oil inventories consist of the following volumes:
			December 31,
	MBbls		2013			2012
	Crude oil line fill requirements		370			391
	Temporarily stored crude oil		344			211
	Total		714			602
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, 2011 through December 31, 2013:
	In thousands		2013				2012			2011
	Asset retirement obligations at January 1		$	47,171			$	62,625		$	56,320
	Accretion expense		2,767				3,105			3,163
	Revisions		2,826				(2,871		)	1,947
	Plus: Additions for new assets		6,009				6,679			3,559
	Less: Plugging costs and sold assets (1)		(2,986		)		(22,367		)	(2,364		)
	Total asset retirement obligations at December 31		$	55,787			$	47,171		$	62,625
	Less: Current portion of asset retirement obligations at December 31 (2)		1,434				2,227			2,287
	Non-current portion of asset retirement obligations at December 31		$	54,353			$	44,944		$	60,338
	-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.
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, 2013, 2012 and 2011. All stock options issued by the Company in prior periods had been exercised or had expired as of March 31, 2012.
			Year ended December 31,
	In thousands, except per share data		2013				2012			2011
	Income (numerator):
	Net income - basic and diluted		$	764,219			$	739,385		$	429,072
	Weighted average shares (denominator):
	Weighted average shares - basic		184,075				181,340			177,590
	Non-vested restricted stock		774				490			544
	Stock options		—				16			96
	Weighted average shares - diluted		184,849				181,846			178,230
	Net income per share:
	Basic		$	4.15			$	4.08		$	2.42
	Diluted		$	4.13			$	4.07		$	2.41

Supplemental_Cash_Flow_Informa1

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2013
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	2013			2012			2011
	Supplemental cash flow information:
	Cash paid for interest	$	209,815		$	102,043		$	70,088
	Cash paid for income taxes	29,017			829			16,030
	Cash received for income tax refunds	(174		)	(13,866		)	(116		)
	Non-cash investing activities:
	Increase in accrued capital expenditures	89,482			49,039			173,591
	Acquisition of assets through issuance of common stock (Note 14)	—			176,563			—
	Asset retirement obligation additions and revisions, net	8,835			3,808			5,506

Net_Property_and_Equipment_Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2013
Property, Plant and Equipment, Net [Abstract]	'
Schedule of Net Property and Equipment	'
	Net property and equipment includes the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Proved crude oil and natural gas properties	$	12,423,878		$	8,980,505
	Unproved crude oil and natural gas properties		1,181,268			1,073,944
	Service properties, equipment and other		236,233			170,763
	Total property and equipment		13,841,379			10,225,212
	Accumulated depreciation, depletion and amortization		(3,120,107	)		(2,119,943	)
	Net property and equipment	$	10,721,272		$	8,105,269

Accrued_Liabilities_and_Other_

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2013
Accrued Liabilities and Other Liabilities [Abstract]	'
Schedule of Accrued Liabilities and Other	'
	Accrued liabilities and other includes the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013		2012
	Prepaid advances from joint interest owners	$	57,196	$	30,434
	Accrued compensation		41,757		27,797
	Accrued production taxes, ad valorem taxes and other non-income taxes		35,900		33,466
	Accrued income taxes		—		10,455
	Accrued interest		61,216		46,973
	Current portion of asset retirement obligations		1,434		2,227
	Other		610		4,329
	Accrued liabilities and other	$	198,113	$	155,681

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2013
Derivative [Line Items]	'
Summary of Outstanding Contracts with Respect to Crude Oil	'
	At December 31, 2013, the Company had outstanding derivative contracts with respect to future production as set forth in the tables below.
	Crude Oil–NYMEX WTI				Swaps Weighted Average Price
	Period and Type of Contract	Bbls
	January 2014 - December 2014
	Swaps - WTI	10,851,250			$	96.5
Summary of Outstanding Contracts with Respect to Natural Gas	'
	Natural Gas–NYMEX Henry Hub	MMBtus			Swaps
					Weighted
					Average
	Period and Type of Contract				Price
	January 2014 - December 2014
	Swaps - Henry Hub	64,250,000			$	4.19
	January 2015 - March 2015
	Swaps - Henry Hub	1,800,000			$	4.27
Realized and Unrealized Gains and Losses on Derivative Instruments	'
	The following table presents cash settlements on matured derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect the gain or loss 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 during the period.
		Year ended December 31,
	In thousands	2013				2012				2011
	Cash received (paid) on derivatives:
	Crude oil fixed price swaps	$	(54,289	)		$	(40,238	)		$	(14,900	)
	Crude oil collars	(16,867		)		(15,341		)		(56,511		)
	Natural gas fixed price swaps	9,601				9,858				37,305
	Cash paid on derivatives, net	$	(61,555	)		$	(45,721	)		$	(34,106	)
	Non-cash gain (loss) on derivatives:
	Crude oil fixed price swaps	$	(117,580	)		$	142,567			$	(23,486	)
	Crude oil collars	(8,587		)		59,911				42,239
	Natural gas fixed price swaps	(4,029		)		(2,741		)		(14,696		)
	Non-cash gain (loss) on derivatives, net	$	(130,196	)		$	199,737			$	4,057
	Gain (loss) on derivative instruments, net	$	(191,751	)		$	154,016			$	(30,049	)
Fair Value of Derivatives not Accounted for Using Hedge Accounting	'
	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, 2013												December 31, 2012
	In thousands	Gross				Gross amounts				Net amounts of				Gross				Gross amounts				Net amounts of
		amounts of				offset on				assets on				amounts of				offset on				assets on
		recognized				balance sheet				balance sheet				recognized				balance sheet				balance sheet
		assets												assets
	Commodity derivative assets	$	4,213			$	(597	)		$	3,616			$	86,506			$	(35,886	)		$	50,620
		December 31, 2013												December 31, 2012
	In thousands	Gross				Gross amounts				Net amounts of				Gross				Gross amounts				Net amounts of
		amounts of				offset on				liabilities on				amounts of				offset on				liabilities on
		recognized				balance sheet				balance sheet				recognized				balance sheet				balance sheet
		liabilities												liabilities
	Commodity derivative liabilities	$	(125,709	)		$	27,345			$	(98,364	)		$	(16,241	)		$	1,069			$	(15,172	)
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.
	In thousands	December 31, 2013				December 31, 2012
	Derivative assets	$	3,616			$	18,389
	Noncurrent derivative assets	—				32,231
	Net amounts of assets on balance sheet	3,616				50,620
	Derivative liabilities	(90,535		)		(12,999		)
	Noncurrent derivative liabilities	(7,829		)		(2,173		)
	Net amounts of liabilities on balance sheet	(98,364		)		(15,172		)
	Total derivative assets (liabilities), net	$	(94,748	)		$	35,448
ICE Brent [Member]	'
Derivative [Line Items]	'
Summary of Outstanding Contracts with Respect to Crude Oil	'
					Swaps				Collars
					Weighted
	Crude Oil–ICE Brent	Bbls			Average				Floors								Ceilings
	Period and Type of Contract				Price				Range				Weighted				Range				Weighted
													Average								Average
													Price								Price
	January 2014 - December 2014
	Swaps - ICE Brent	17,028,000			$	103.17
	Collars - ICE Brent	2,190,000							$90.00 - $95.00				$	90.83			$104.70 - $108.85				$	107.13
	January 2015 - December 2015
	Swaps - ICE Brent	2,737,500			$	99.15
	Collars - ICE Brent	730,000							$	95			$	95			$	107.4			$	107.4

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2013 and 2012.
	In thousands	Fair value measurements at December 31, 2013 using:
	Description	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	)
	In thousands	Fair value measurements at December 31, 2012 using:
	Description	Level 1		Level 2			Level 3		Total
	Derivative assets (liabilities):
	Fixed price swaps	$	—	$	36,716		$	—	$	36,716
	Collars	—		(1,268		)	—		(1,268		)
	Total	$	—	$	35,448		$	—	$	35,448
Reconciliation of Changes in Fair Value of Financial Assets and Liabilities Classified as Level 3	'
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 income.
		Year ended December 31,
	In thousands	2013		2012			2011
	Proved property impairments	$	51,805	$	4,332		$	16,107
	Unproved property impairments	168,703		117,942			92,351
	Total	$	220,508	$	122,274		$	108,458
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, 2013					December 31, 2012
	In thousands	Carrying Amount		Fair Value			Carrying Amount		Fair Value
	Debt:
	Credit facility	$	275,000	$	275,000		$	595,000	$	595,000
	Note payable	18,470		16,500			20,421		20,148
	8 1/4% Senior Notes due 2019	298,305		327,800			298,085		339,000
	7 3/8% Senior Notes due 2020	198,695		223,700			198,552		226,833
	7 1/8% Senior Notes due 2021	400,000		450,300			400,000		454,333
	5% Senior Notes due 2022	2,025,362		2,063,300			2,027,663		2,165,833
	4 1/2% Senior Notes due 2023	1,500,000		1,519,400			—		—
	Total debt	$	4,715,832	$	4,876,000		$	3,539,721	$	3,801,147

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-term debt consists of the following at December 31, 2013 and 2012:
			December 31,
	In thousands		2013			2012
	Credit facility		$	275,000		$	595,000
	Note payable		18,470			20,421
	8 1/4% Senior Notes due 2019 (1)		298,305			298,085
	7 3/8% Senior Notes due 2020 (2)		198,695			198,552
	7 1/8% Senior Notes due 2021 (3)		400,000			400,000
	5% Senior Notes due 2022 (4)		2,025,362			2,027,663
	4 1/2% Senior Notes due 2023 (3)		1,500,000			—
	Total debt		4,715,832			3,539,721
	Less: Current portion of long-term debt		(2,011		)	(1,950		)
	Long-term debt, net of current portion		$	4,713,821		$	3,537,771
	-1	The carrying amount is net of unamortized discounts of $1.7 million and $1.9 million at December 31, 2013 and 2012, respectively.
	-2	The carrying amount is net of unamortized discounts of $1.3 million and $1.4 million at December 31, 2013 and 2012, 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 $25.4 million and $27.7 million at December 31, 2013 and 2012, respectively.
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.
			2019 Notes		2020 Notes	2021 Notes		2022 Notes	2023 Notes
	Maturity date		Oct 1, 2019		Oct 1, 2020	April 1, 2021		Sep 15, 2022	April 15, 2023
	Interest payment dates		April 1, Oct. 1		April 1, Oct. 1	April 1, Oct. 1		March 15, Sept. 15	April 15, Oct. 15
	Call premium redemption period (1)		Oct 1, 2014		Oct 1, 2015	April 1, 2016		March 15, 2017	n/a
	Make-whole redemption period (2)		Oct 1, 2014		Oct 1, 2015	April 1, 2016		March 15, 2017	Jan 15, 2023
	Equity offering redemption period (3)		—		—	April 1, 2014		March 15, 2015	n/a
	-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 specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
	-3	At any time prior to these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption period for the 2019 Notes and 2020 Notes using equity offering proceeds expired on October 1, 2012 and October 1, 2013, respectively.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2013
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		2013			2012			2011
	Current income tax provision:
	Federal		$	6,193		$	9,191		$	12,931
	State		16			1,326			239
	Total current income tax provision		6,209			10,517			13,170
	Deferred income tax provision:
	Federal		403,002			383,157			212,406
	State		39,619			22,137			32,797
	Total deferred income tax provision		442,621			405,294			245,203
	Total provision for income taxes		$	448,830		$	415,811		$	258,373
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	'
	The following table reconciles the provision for income taxes with income tax at the Federal statutory rate for the periods presented:
			Year ended December 31,
	In thousands		2013			2012			2011
	Federal income tax provision at statutory rate (35%)		$	424,567		$	404,319		$	240,606
	State income tax provision, net of Federal benefit		25,838			15,213			17,684
	Other, net		(1,575		)	(3,721		)	83
	Provision for income taxes		$	448,830		$	415,811		$	258,373
Components of Deferred Tax Assets and Liabilities	'
	The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are as follows:
			December 31,
	In thousands		2013			2012
	Current:
	Deferred tax assets (1)
	Non-cash losses on derivatives		$	33,029		$	—
	Other		2,288			2,413
	Total current deferred tax assets		35,317			2,413
	Deferred tax liabilities
	Other		645			2,048
	Total current deferred tax liabilities		645			2,048
	Net current deferred tax assets		34,672			365
	Noncurrent:
	Deferred tax assets
	Net operating loss carryforwards		41,791			40,441
	Non-cash losses on derivatives		2,975			—
	Alternative minimum tax carryforwards		38,689			27,380
	Other		20,220			11,576
	Total noncurrent deferred tax assets		103,675			79,397
	Deferred tax liabilities
	Property and equipment		1,840,331			1,330,551
	Other		156			11,422
	Total noncurrent deferred tax liabilities		1,840,487			1,341,973
	Net noncurrent deferred tax liabilities		1,736,812			1,262,576
	Net deferred tax liabilities (2)		$	1,702,140		$	1,262,211
	-1	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $9.7 million for prepaid income taxes at December 31, 2013, with no such prepayments at December 31, 2012.
	-2	In addition to the 2012 provision for income taxes of $415.8 million, activity during 2012 includes an increase to deferred tax liabilities of $56.6 million related to the acquisition of assets from Wheatland Oil Inc. (see Note 14) and a decrease of $15.6 million related to the excess tax benefits of stock-based compensation.

Lease_Commitments_Tables

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2013
Leases [Abstract]	'
Schedule of Minimum Future Rental Commitments Under Operating Leases	'
	At December 31, 2013 the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows:
		Total amount
	In these years	In thousands
	2014	$	1,954
	2015	432
	2016	346
	2017	255
	2018	151
	Thereafter	182
	Total obligations	$	3,320

StockBased_Compensation_Tables

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2013
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 income, is reflected in the table below for the periods presented.
		Year ended December 31,
	In thousands	2013			2012			2011
	Non-cash equity compensation	$	39,890		$	29,057		$	16,572
Schedule of Stock Option Activity	'
	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, 2010	104,970		$	0.71		104,970			$	0.71
	Exercised	(18,470	)	$	0.71
	Outstanding at December 31, 2011	86,500		$	0.71		86,500			$	0.71
	Exercised	(86,500	)	$	0.71
	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, 2010 to December 31, 2013 is presented below:
		Number of		Weighted
		non-vested		average
		shares		grant-date
				fair value
	Non-vested restricted shares at December 31, 2010	1,108,077		$	35.72
	Granted	491,315		63.59
	Vested	(359,601	)	29.95
	Forfeited	(41,447	)	41.93
	Non-vested restricted shares at December 31, 2011	1,198,344		$	48.66
	Granted	916,028		73.46
	Vested	(444,723	)	45.25
	Forfeited	(40,187	)	59.05
	Non-vested restricted shares at December 31, 2012	1,629,462		$	63.28
	Granted	261,259		97.95
	Vested	(464,809	)	47.3
	Forfeited	(68,756	)	71.91
	Non-vested restricted shares at December 31, 2013	1,357,156		$	74.99

Crude_Oil_and_Natural_Gas_Prop1

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2013
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 results of operations from crude oil and natural gas producing activities for the years ended December 31, 2013, 2012 and 2011.
		Year ended December 31,
	In thousands	2013			2012			2011
	Crude oil and natural gas sales	$	3,606,774		$	2,379,433		$	1,647,419
	Production expenses	(282,197		)	(195,440		)	(138,236		)
	Production taxes and other expenses	(332,130		)	(228,438		)	(144,810		)
	Exploration expenses	(34,947		)	(23,507		)	(27,920		)
	Depreciation, depletion, amortization and accretion	(953,796		)	(683,207		)	(384,301		)
	Property impairments	(220,508		)	(122,274		)	(108,458		)
	Income taxes	(659,783		)	(428,095		)	$	(321,447	)
	Results from crude oil and natural gas producing activities	$	1,123,413		$	698,472		$	522,247
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 crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2013, 2012 and 2011 are presented below:
		Year ended December 31,
	In thousands	2013			2012			2011
	Property Acquisition Costs:
	Proved	$	16,604		$	738,415		$	65,315
	Unproved	546,881			745,601			183,247
	Total property acquisition costs	563,485			1,484,016			248,562
	Exploration Costs	687,767			857,681			734,797
	Development Costs	2,549,203			1,975,660			1,178,136
	Total	$	3,800,455		$	4,317,357		$	2,161,495
Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities	'
	Aggregate capitalized costs relating to the Company’s crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2013 and 2012 are as follows:
		December 31,
	In thousands	2013			2012
	Proved crude oil and natural gas properties	$	12,423,878		$	8,980,505
	Unproved crude oil and natural gas properties	1,181,268			1,073,944
	Total	13,605,146			10,054,449
	Less accumulated depreciation, depletion and amortization	(3,083,180		)	(2,090,845		)
	Net capitalized costs	$	10,521,966		$	7,963,604
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	2013			2012			2011
	Balance at January 1	$	92,699		$	128,123		$	92,806
	Additions to capitalized exploratory well costs pending determination of proved reserves	548,933			485,530			500,046
	Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(479,507		)	(520,187		)	(456,780		)
	Capitalized exploratory well costs charged to expense	(9,350		)	(767		)	(7,949		)
	Balance at December 31	$	152,775		$	92,699		$	128,123
	Number of gross wells	67			46			56

Supplemental_Crude_Oil_and_Nat1

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
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, 2010	224,784			839,568			364,712
	Revisions of previous estimates	28,607			(158,219	)		2,237
	Extensions, discoveries and other additions	87,465			447,098			161,981
	Production	(16,469	)		(36,671	)		(22,581	)
	Sales of minerals in place	—			—			—
	Purchases of minerals in place	1,746			2,056			2,089
	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
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, 2013, 2012 and 2011:
		December 31,
		2013			2012			2011
	Proved Developed Reserves
	Crude oil (MBbl)	278,630			226,870			145,024
	Natural Gas (MMcf)	768,969			545,499			361,265
	Total (MBoe)	406,792			317,786			205,235
	Proved Undeveloped Reserves
	Crude oil (MBbl)	459,158			334,293			181,109
	Natural Gas (MMcf)	1,309,051			795,585			732,567
	Total (MBoe)	677,333			466,891			303,203
	Total Proved Reserves
	Crude oil (MBbl)	737,788			561,163			326,133
	Natural Gas (MMcf)	2,078,020			1,341,084			1,093,832
	Total (MBoe)	1,084,125			784,677			508,438
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, 2013, 2012 and 2011.
		December 31,
	In thousands	2013				2012				2011
	Future cash inflows	$	78,646,274			$	54,362,574			$	35,042,916
	Future production costs	(21,333,460		)		(13,103,469		)		(7,495,552		)
	Future development and abandonment costs	(10,250,789		)		(8,295,130		)		(5,073,043		)
	Future income taxes	(12,447,127		)		(8,500,766		)		(5,956,615		)
	Future net cash flows	34,614,898				24,463,209				16,517,706
	10% annual discount for estimated timing of cash flows	(18,319,131		)		(13,282,852		)		(9,012,350		)
	Standardized measure of discounted future net cash flows	$	16,295,767			$	11,180,357			$	7,505,356
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	2013				2012				2011
	Standardized measure of discounted future net cash flows at January 1	$	11,180,357			$	7,505,356			$	3,785,322
	Extensions, discoveries and improved recoveries, less related costs	6,613,665				3,724,136				2,276,355
	Revisions of previous quantity estimates	(1,765,300		)		254,493				133,990
	Changes in estimated future development and abandonment costs	1,942,585				(298,148		)		(70,219		)
	Purchases (sales) of minerals in place, net	12,012				1,171,047				56,246
	Net change in prices and production costs	263,541				(530,515		)		1,855,532
	Accretion of discount	1,118,036				750,536				378,532
	Sales of crude oil and natural gas produced, net of production costs	(2,992,447		)		(1,955,555		)		(1,364,373		)
	Development costs incurred during the period	1,210,223				1,095,156				528,737
	Change in timing of estimated future production and other	464,111				(102,519		)		773,279
	Change in income taxes	(1,751,016		)		(433,630		)		(848,045		)
	Net change	5,115,410				3,675,001				3,720,034
	Standardized measure of discounted future net cash flows at December 31	$	16,295,767			$	11,180,357			$	7,505,356

Quarterly_Financial_Data_Unaud1

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]	'
Schedule Of Quarterly Financial Data	'
	The Company’s unaudited quarterly financial data for 2013 and 2012 is summarized below.
			Quarter ended
	In thousands, except per share data		March 31			June 30		September 30			December 31
	2013
	Total revenues (1)		$	710,229		$	1,100,752	$	823,835		$	820,334
	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		$	0.76		$	1.76	$	0.91		$	0.72
	Diluted		$	0.76		$	1.75	$	0.91		$	0.72
	2012
	Total revenues (1)		$	395,100		$	1,004,719	$	483,729		$	688,972
	Gain (loss) on derivative instruments, net (1)		$	(169,057	)	$	471,728	$	(158,294	)	$	9,639
	Income from operations		$	135,591		$	686,474	$	105,522		$	365,220
	Net income		$	69,094		$	405,684	$	44,096		$	220,511
	Net income per share:
	Basic		$	0.38		$	2.26	$	0.24		$	1.2
	Diluted		$	0.38		$	2.25	$	0.24		$	1.19
	-1	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of 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.

Organization_and_Summary_of_Si3

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	Well
Organization And Summary Of Significant Accounting Policies [Line Items]	'	'	'	'
Percentage of operations concentrated in geographically areas	77.00%	'	'	'
Percentage Of Revenues Concentrated In Geographically Areas	86.00%	'	'	'
Percentage of estimated proved reserves in north region	76.00%	'	'	'
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil	71.00%	'	'	'
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil	87.00%	'	'	'
Cash deposits in excess of federally insured amounts	$28,000,000	'	'	'
Capitalized exploratory drilling cost pending determination of proved reserves	152,775,000	92,699,000	128,123,000	92,806,000
Exploratory drilling costs	3,900,000	'	'	'
Number of exploratory drilling wells suspended	3	'	'	'
Suspended well costs, incurred	500,000	1,500,000	0	1,900,000
Net asset retirement costs	44,400,000	36,600,000	'	'
Capitalized costs, relating to long-term debt	69,500,000	55,300,000	'	'
Accumulated amortization, relating to long-term debt	28,800,000	20,200,000	'	'
Amortization expense related to capitalized debt issuance costs	$8,600,000	$5,600,000	$3,300,000	'
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil	68.00%	'	'	'
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	15.00%	21.00%	41.00%	'
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	12.00%	11.00%	'	'
Third 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%	'	'	'

Organization_and_Summary_of_Si4

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'	'
Tubular goods and equipment	$11,139	$13,590
Crude oil	43,301	33,153
Total	$54,440	$46,743

Organization_and_Summary_of_Si5

Organization and Summary of Significant Accounting Policies - Components of Crude Oil Inventories Volumes (Detail)	Dec. 31, 2013	Dec. 31, 2012
	MBbls	MBbls
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'	'
Crude oil line fill requirements, in thousands of barrels	370	391
Temporarily stored crude oil, in thousands of barrels	344	211
Total, in thousands of barrels	714	602

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, 2013
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, 2013		Dec. 31, 2012		Dec. 31, 2011
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'		'
Asset retirement obligations at January 1	$47,171,000		$62,625,000		$56,320,000
Accretion expense	2,767,000		3,105,000		3,163,000
Revisions	2,826,000		-2,871,000		1,947,000
Plus: Additions for new assets	6,009,000		6,679,000		3,559,000
Less: Plugging costs and sold assets	2,986,000	[1]	22,367,000	[1]	2,364,000	[1]
Total asset retirement obligations at December 31	55,787,000		47,171,000		62,625,000
Less: Current portion of asset retirement obligations at December 31	1,434,000		2,227,000		2,287,000
Non-current portion of asset retirement obligations at December 31	54,353,000		44,944,000		60,338,000
Asset retirement obligation disposed off	'		$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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income (numerator):	'	'	'	'	'	'	'	'	'	'	'
Net income - basic and diluted	$132,824	$167,498	$323,270	$140,627	$220,511	$44,096	$405,684	$69,094	$764,219	$739,385	$429,072
Weighted average shares - basic	'	'	'	'	'	'	'	'	184,075	181,340	177,590
Non-vested restricted stock	'	'	'	'	'	'	'	'	774	490	544
Stock options	'	'	'	'	'	'	'	'	0	16	96
Weighted average shares - diluted	'	'	'	'	'	'	'	'	184,849	181,846	178,230
Net income per share:	'	'	'	'	'	'	'	'	'	'	'
Basic (in dollars per share)	$0.72	$0.91	$1.76	$0.76	$1.20	$0.24	$2.26	$0.38	$4.15	$4.08	$2.42
Diluted (in dollars per share)	$0.72	$0.91	$1.75	$0.76	$1.19	$0.24	$2.25	$0.38	$4.13	$4.07	$2.41

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental cash flow information:	'	'	'
Cash paid for interest	$209,815	$102,043	$70,088
Cash paid for income taxes	29,017	829	16,030
Cash received for income tax refunds	-174	-13,866	-116
Non-cash investing activities:	'	'	'
Increase in accrued capital expenditures	89,482	49,039	173,591
Acquisition of assets through issuance of common stock (Note 14)	0	176,563	0
Asset retirement obligation additions and revisions, net	$8,835	$3,808	$5,506

Net_Property_and_Equipment_Sch

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment, Net [Abstract]	'	'
Proved crude oil and natural gas properties	$12,423,878	$8,980,505
Unproved crude oil and natural gas properties	1,181,268	1,073,944
Service properties, equipment and other	236,233	170,763
Total property and equipment	13,841,379	10,225,212
Accumulated depreciation, depletion and amortization	-3,120,107	-2,119,943
Net property and equipment	$10,721,272	$8,105,269

Accrued_Liabilities_and_Other_1

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
In Thousands, unless otherwise specified
Accrued Liabilities and Other Liabilities [Abstract]	'	'	'
Prepaid advances from joint interest owners	$57,196	$30,434	'
Accrued compensation	41,757	27,797	'
Accrued production taxes, ad valorem taxes and other non-income taxes	35,900	33,466	'
Accrued income taxes	0	10,455	'
Accrued interest	61,216	46,973	'
Current portion of asset retirement obligations	1,434	2,227	2,287
Other	610	4,329	'
Accrued liabilities and other	$198,113	$155,681	'

Derivative_Instruments_Summary

Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail)	12 Months Ended
	Dec. 31, 2013
	bbl
West Texas Intermediate [Member] | January 2014 to December 2014 Swaps [Member]	'
Derivative [Line Items]	'
Volume (Bbls)	10,851,250
Swaps Weighted Average Price	96.5
ICE Brent [Member] | January 2014 to December 2014 Swaps [Member]	'
Derivative [Line Items]	'
Volume (Bbls)	17,028,000
Swaps Weighted Average Price	103.17
ICE Brent [Member] | January 2014 to December 2014 Collars [Member]	'
Derivative [Line Items]	'
Volume (Bbls)	2,190,000
Floors, Weighted Average Price	90.83
Ceilings, Weighted Average Price	107.13
ICE Brent [Member] | January 2015 to December 2015 Swaps [Member]	'
Derivative [Line Items]	'
Volume (Bbls)	2,737,500
Swaps Weighted Average Price	99.15
ICE Brent [Member] | January 2015 to December 2015 Collars [Member]	'
Derivative [Line Items]	'
Volume (Bbls)	730,000
Floors, Range	95
Floors, Weighted Average Price	95
Ceilings, Range	107.4
Ceilings, Weighted Average Price	107.4
ICE Brent [Member] | Minimum [Member] | January 2014 to December 2014 Collars [Member]	'
Derivative [Line Items]	'
Floors, Range	90
Ceilings, Range	104.7
ICE Brent [Member] | Maximum [Member] | January 2014 to December 2014 Collars [Member]	'
Derivative [Line Items]	'
Floors, Range	95
Ceilings, Range	108.85

Derivative_Instruments_Summary1

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) (Natural Gas [Member])	12 Months Ended
	Dec. 31, 2013
	MMBTU
January 2014 to December 2014 Swaps [Member]	'
Derivative [Line Items]	'
Natural Gas Production Derivative Volume, MMBtus	64,250,000
Swaps Weighted Average Price	4.19
January 2015 to March 2015 Swaps [Member]	'
Derivative [Line Items]	'
Natural Gas Production Derivative Volume, MMBtus	1,800,000
Swaps Weighted Average Price	4.27

Derivative_Instruments_Realize

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

3 Months Ended

12 Months Ended

In Thousands, unless otherwise specified

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2012

Sep. 30, 2012

Jun. 30, 2012

Mar. 31, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Cash received (paid) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Cash paid on derivatives, net

'

'

'

'

'

'

'

'

($61,555)

($45,721)

($34,106)

Non-cash gain (loss) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Non-cash gain (loss) on derivatives, net

'

'

'

'

'

'

'

'

-130,196

199,737

4,057

Gain (loss) on derivative instruments, net

-102,202

[1]

-203,774

[1]

199,056

[1]

-84,831

[1]

9,639

[1]

-158,294

[1]

471,728

[1]

-169,057

[1]

-191,751

154,016

-30,049

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

'

'

'

'

'

'

'

'

'

'

'

Cash received (paid) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Cash paid on derivatives, net

'

'

'

'

'

'

'

'

-54,289

-40,238

-14,900

Non-cash gain (loss) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Non-cash gain (loss) on derivatives, net

'

'

'

'

'

'

'

'

-117,580

142,567

-23,486

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

'

'

'

'

'

'

'

'

'

'

'

Cash received (paid) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Cash paid on derivatives, net

'

'

'

'

'

'

'

'

9,601

9,858

37,305

Non-cash gain (loss) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Non-cash gain (loss) on derivatives, net

'

'

'

'

'

'

'

'

-4,029

-2,741

-14,696

Collars [Member] | Crude Oil [Member]

'

'

'

'

'

'

'

'

'

'

'

Cash received (paid) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Cash paid on derivatives, net

'

'

'

'

'

'

'

'

-16,867

-15,341

-56,511

Non-cash gain (loss) on derivatives:

'

'

'

'

'

'

'

'

'

'

'

Non-cash gain (loss) on derivatives, net

'

'

'

'

'

'

'

'

($8,587)

$59,911

$42,239

[1]

Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of 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.

Derivative_Instruments_Derivat

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Commodity derivative assets, Gross amounts of recognized assets	$4,213	$86,506
Commodity derivative assets, Gross amounts offset on balance sheet	-597	-35,886
Derivative assets, Net amounts of assets on balance sheet	3,616	50,620
Commodity derivative liability, Gross amounts of recognized liabilities	-125,709	-16,241
Commodity derivative liability, Gross amounts offset on balance sheet	27,345	1,069
Derivative liability, Net amounts of liabilities on balance sheet	($98,364)	($15,172)

Derivative_Instruments_Derivat1

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'	'
Derivative assets	$3,616	$18,389
Noncurrent derivative assets	0	32,231
Derivative assets, Net amounts of assets on balance sheet	3,616	50,620
Derivative liabilities	-90,535	-12,999
Noncurrent derivative liabilities	-7,829	-2,173
Derivative liability, Net amounts of liabilities on balance sheet	-98,364	-15,172
Total derivative assets (liabilities), net	($94,748)	$35,448

Fair_Value_Measurements_Valuat

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) (USD $)	Dec. 31, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Derivative assets (liabilities):	'	'
Derivative assets (liabilities)	($94,748)	$35,448
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)	-94,748	35,448
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]	'	'
Derivative assets (liabilities):	'	'
Derivative assets (liabilities)	-84,893	36,716
Fair Value, Inputs, Level 2 [Member] | Collars [Member]	'	'
Derivative assets (liabilities):	'	'
Derivative assets (liabilities)	-9,855	-1,268
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)	-94,748	35,448
Fair Value [Member] | Fixed Price Swaps [Member]	'	'
Derivative assets (liabilities):	'	'
Derivative assets (liabilities)	-84,893	36,716
Fair Value [Member] | Collars [Member]	'	'
Derivative assets (liabilities):	'	'
Derivative assets (liabilities)	($9,855)	($1,268)

Fair_Value_Measurements_Additi

Fair Value Measurements - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	$51,805,000	$4,332,000	$16,107,000
Estimated fair value of proved properties	21,200,000	'	'
Unproved Oil And Gas Property Fair Value After Impairment	14,900,000	'	'
Impairment of individually significant unproved property	$8,400,000	'	'
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%	'	'

Fair_Value_Measurements_Proper

Fair Value Measurements - Property Impairments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value Disclosures [Abstract]	'	'	'
Proved property impairments	$51,805	$4,332	$16,107
Unproved property impairments	168,703	117,942	92,351
Total	$220,508	$122,274	$108,458

Fair_Value_Measurements_Fair_V

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) (USD $)	Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Fair Value Measurements [Line Items]	'		'
Revolving credit facility	$275,000		$595,000
Carrying Amount [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Revolving credit facility	275,000		595,000
Note payable	18,470		20,421
Total debt	4,715,832		3,539,721
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	298,305	[1]	298,085	[1]
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	198,695	[2]	198,552	[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	2,025,362	[4]	2,027,663	[4]
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	1,500,000	[3]	0	[3]
Fair Value [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Revolving credit facility	275,000		595,000
Note payable	16,500		20,148
Total debt	4,876,000		3,801,147
Fair Value [Member] | 8 1/4% Senior Notes due 2019 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	327,800		339,000
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	223,700		226,833
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	450,300		454,333
Fair Value [Member] | 5% Senior Notes due 2022 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	2,063,300		2,165,833
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]	'		'
Fair Value Measurements [Line Items]	'		'
Senior notes	$1,519,400		$0
[1]	The carrying amount is net of unamortized discounts of $1.7 million and $1.9 million at December 31, 2013 and 2012, respectively.
[2]	The carrying amount is net of unamortized discounts of $1.3 million and $1.4 million at December 31, 2013 and 2012, 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 $25.4 million and $27.7 million at December 31, 2013 and 2012, respectively.

Fair_Value_Measurements_Fair_V1

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
8 1/4% Senior Notes due 2019 [Member]	'
Fair Value Measurements [Line Items]	'
Debt instrument, stated interest rate	8.25%
Debt instrument, maturity date	'2019
7 3/8% Senior Notes due 2020 [Member]	'
Fair Value Measurements [Line Items]	'
Debt instrument, stated interest rate	7.38%
Debt instrument, maturity date	'2020
7 1/8% Senior Notes due 2021 [Member]	'
Fair Value Measurements [Line Items]	'
Debt instrument, stated interest rate	7.13%
Debt instrument, maturity date	'2021
5% Senior Notes due 2022 [Member]	'
Fair Value Measurements [Line Items]	'
Debt instrument, stated interest rate	5.00%
Debt instrument, maturity date	'2022
4.5% Senior Notes due 2023 [Member]	'
Fair Value Measurements [Line Items]	'
Debt instrument, stated interest rate	4.50%
Debt instrument, maturity date	'2023

LongTerm_Debt_LongTerm_Debt_De

Long-Term Debt - Long-Term Debt (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Proforma Debt Instrument [Line Items]	'		'
Line of Credit Facility, Present Value Ratio	1.5		'
Revolving credit facility	$275,000,000		$595,000,000
Less: Current portion of long-term debt	-2,011,000		-1,950,000
Long-term debt, net of current portion	4,713,821,000		3,537,771,000
8 1/4% Senior Notes due 2019 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Debt instrument, stated interest rate	8.25%		'
Discounts	1,700,000		1,900,000
7 3/8% Senior Notes due 2020 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Debt instrument, stated interest rate	7.38%		'
Discounts	1,300,000		1,400,000
7 1/8% Senior Notes due 2021 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Debt instrument, stated interest rate	7.13%		'
5% Senior Notes due 2022 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Debt instrument, stated interest rate	5.00%		'
Amortization of Debt Discount (Premium)	25,400,000		27,700,000
4.5% Senior Notes due 2023 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Debt instrument, stated interest rate	4.50%		'
Senior Notes [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes recorded as percentage of face value	100.00%		'
Carrying Amount [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Revolving credit facility	275,000,000		595,000,000
Note payable	18,470,000		20,421,000
Total debt	4,715,832,000		3,539,721,000
Carrying Amount [Member] | 8 1/4% Senior Notes due 2019 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes	298,305,000	[1]	298,085,000	[1]
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes	198,695,000	[2]	198,552,000	[2]
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes	400,000,000	[3]	400,000,000	[3]
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes	2,025,362,000	[4]	2,027,663,000	[4]
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]	'		'
Proforma Debt Instrument [Line Items]	'		'
Senior notes	$1,500,000,000	[3]	$0	[3]
[1]	The carrying amount is net of unamortized discounts of $1.7 million and $1.9 million at December 31, 2013 and 2012, respectively.
[2]	The carrying amount is net of unamortized discounts of $1.3 million and $1.4 million at December 31, 2013 and 2012, 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 $25.4 million and $27.7 million at December 31, 2013 and 2012, respectively.

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended				12 Months Ended		1 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2013	Dec. 31, 2013	Apr. 30, 2013	Dec. 31, 2013	Apr. 30, 2013	Dec. 31, 2013	Dec. 31, 2013
				Revolving Credit Facility [Member]	Note Payable [Member]	5% Senior Notes due 2022 [Member]	Senior Notes Due Two Thousand And Twenty Three [Member]	Senior Notes Due Two Thousand And Twenty Three [Member]	Revolving Credit Facility [Member]	Prime Rate [Member]	London Interbank Offered Rate (LIBOR) [Member]
									Senior Notes Due Two Thousand And Twenty Three [Member]	Minimum [Member]	Minimum [Member]
Debt Instrument [Line Items]	'	'	'	'	'	'	'	'	'	'	'
Line of credit facility, amount outstanding	$275,000,000	$595,000,000	'	'	'	'	'	'	'	'	'
Aggregate amount of lender commitments on credit facility	1,500,000,000	'	'	'	'	'	'	'	'	'	'
Maximum borrowing capacity	2,500,000,000	'	'	'	'	'	'	'	'	'	'
Basis points	'	'	'	'	'	'	'	'	'	0.50%	1.50%
Debt instrument, covenant description	'Collateral Coverage Ratio, as defined in the amended credit agreement, is greater than or equal to 1.75 to 1.0	'	'	'	'	'	'	'	'	'	'
Line of credit facility, unused commitments	'	'	'	1,200,000,000	'	'	'	'	'	'	'
Line of credit facility, commitment fee percentage, per annum	0.25%	'	'	'	'	'	'	'	'	'	'
Credit facility current ratio covenant requirement	1	'	'	'	'	'	'	'	'	'	'
Ratio of total funded debt to EBITDAX	4	'	'	'	'	'	'	'	'	'	'
Senior notes	'	'	'	'	'	'	1,500,000,000	'	'	'	'
Proceeds from issuance of Senior Notes	1,479,375,000	1,999,000,000	0	'	'	'	1,480,000,000	'	'	'	'
Repayments of Lines of Credit	1,290,000,000	1,882,000,000	165,000,000	'	'	'	'	'	1,040,000,000	'	'
Debt Instrument Percentage Redeemable	35.00%	'	'	'	'	'	'	'	'	'	'
Notes Payable	'	'	'	'	22,000,000	'	'	'	'	'	'
Loan period, in years	'	'	'	'	'10 years	'	'	'	'	'	'
Debt instrument, stated interest rate	'	'	'	'	3.14%	5.00%	'	'	'	'	'
Debt instrument, maturity date	'	'	'	'	26-Feb-22	'	'	15-Apr-23	'	'	'
Current portion of long-term debt	$2,011,000	$1,950,000	'	'	'	'	'	'	'	'	'

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, 2013
2019 Notes [Member]	'
Debt Instrument [Line Items]	'
Maturity date	1-Oct-19
Interest Payment Dates	'April 1, Oct. 1
Decreasing call premium redemption period	1-Oct-14	[1]
Make-whole redemption period	1-Oct-14	[2]
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]
Redemption using equity offering proceeds	1-Apr-14	[3]
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 Two Thousand And Twenty Three [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]
[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 specified in the Indentures plus any accrued and unpaid interest to the date of redemption.
[3]	At any time prior to these dates, the Company may redeem up to 35% of the principal amount of its senior notes under certain circumstances with the net cash proceeds from one or more equity offerings at the redemption prices specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The optional redemption period for the 2019 Notes and 2020 Notes using equity offering proceeds expired on October 1, 2012 and October 1, 2013, respectively.

Income_Taxes_Provision_for_Inc

Income Taxes - Provision for Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Current tax provision, Federal	$6,193	$9,191	$12,931
Current tax provision, State	16	1,326	239
Total current income tax provision	6,209	10,517	13,170
Deferred tax provision, Federal	403,002	383,157	212,406
Deferred tax provision, State	39,619	22,137	32,797
Total deferred income tax provision	442,621	405,294	245,203
Provision for income taxes	$448,830	$415,811	$258,373

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]	'	'	'
Federal income tax provision at statutory rate (35%)	$424,567	$404,319	$240,606
State income tax provision, net of Federal benefit	25,838	15,213	17,684
Other, net	-1,575	-3,721	83
Provision for income taxes	$448,830	$415,811	$258,373
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, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Income Tax Disclosure [Abstract]	'		'
Deferred tax assets, Non-cash losses on derivatives, Current	$33,029	[1]	$0	[1]
Deferred tax assets, Other, Current	2,288	[1]	2,413	[1]
Total current deferred tax assets	35,317	[1]	2,413	[1]
Deferred tax liabilities, Non-cash gains on derivatives, Current	645		2,048
Total current deferred tax liabilities	645		2,048
Net current deferred tax assets	34,672		365
Deferred tax assets, Net operating loss carryforwards, Noncurrent	41,791		40,441
Deferred tax assets, Non-cash losses on derivatives, Noncurrent	2,975		0
Deferred tax assets, Alternative minimum tax carryforwards, Noncurrent	38,689		27,380
Deferred tax assets, Other, Noncurrent	20,220		11,576
Total noncurrent deferred tax assets	103,675		79,397
Deferred tax liabilities, Property and equipment, Noncurrent	1,840,331		1,330,551
Deferred tax liabilities, Non-cash gains on derivatives, Noncurrent	156		11,422
Total noncurrent deferred tax liabilities	1,840,487		1,341,973
Net noncurrent deferred tax liabilities	1,736,812		1,262,576
Net deferred tax liabilities	$1,702,140	[2]	$1,262,211	[2]
[1]	Deferred and prepaid taxes on the consolidated balance sheets contain receivables of $9.7 million for prepaid income taxes at December 31, 2013, with no such prepayments at December 31, 2012.
[2]	In addition to the 2012 provision for income taxes of $415.8 million, activity during 2012 includes an increase to deferred tax liabilities of $56.6 million related to the acquisition of assets from Wheatland Oil Inc. (see Note 14) and a decrease of $15.6 million related to the excess tax benefits of stock-based compensation.

Income_Taxes_Components_of_Def1

Income Taxes - Components of Deferred Tax Assets and Liabilities (Parenthetical) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Components Of Deferred Tax Assets And Liabilities [Line Items]	'	'	'
Income tax receivable	$9,700,000	$0	'
Provision for income taxes	448,830,000	415,811,000	258,373,000
Increase (decrease) in deferred income tax liabilities	-442,621,000	-405,294,000	-245,203,000
Stock Compensation Plan [Member]	'	'	'
Components Of Deferred Tax Assets And Liabilities [Line Items]	'	'	'
Increase (decrease) in deferred income tax liabilities	'	-15,600,000	'
Wheatland Oil Inc. [Member]	'	'	'
Components Of Deferred Tax Assets And Liabilities [Line Items]	'	'	'
Increase (decrease) in deferred income tax liabilities	'	$56,600,000	'

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	Dec. 31, 2013
Income Tax Disclosure [Abstract]	'
Net operating loss carryforwards, State	$1,009,000,000
Alternative minimum tax credit carryforward	$0

Lease_Commitments_Lease_Commit

Lease Commitments - Lease Commitments (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases [Abstract]	'	'	'
Lease expenses associated with operating leases	$3,000,000	$2,200,000	$1,700,000
2014	1,954,000	'	'
2015	432,000	'	'
2016	346,000	'	'
2017	255,000	'	'
2018	151,000	'	'
Thereafter	182,000	'	'
Total obligations	$3,320,000	'	'

Commitments_and_Contingencies_

Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Long-term Purchase Commitment [Line Items]	'	'
Total future drilling commitments at balance sheet date	$110	'
Drilling commitments 2014	83	'
Drilling commitments 2015	26	'
Drilling Commitments 2016	1	'
Future Commitment For Fracturing And Well Stimulation Services	16	'
Loss related to contingency damages	165	'
Legal proceedings recorded as a liability under other noncurrent liabilities	1.7	2.4
Pipeline Transportation Commitments [Member]	'	'
Long-term Purchase Commitment [Line Items]	'	'
Future commitment, in years	'5 years	'
Future commitment, end date	'2017-11	'
Future commitment, total	43	'
Future commitment, due in 2014	14	'
Future commitment, due in 2015	14	'
Future commitment, due in 2016	10	'
Future commitment, due in 2017	5	'
Pipeline Access Capacity Commitment [Member]	'	'
Long-term Purchase Commitment [Line Items]	'	'
Future commitment, in years	'10 years	'
Long-term Purchase Commitment, Amount	24	'
Non-operational Pipeline Transportation Commitments[Member]	'	'
Long-term Purchase Commitment [Line Items]	'	'
Future commitment, in years	'5 years	'
Future commitment, total	1,000	'
Future commitment, due in 2014	36	'
Transportation commitments per year, due 2015 through 2018	143	'
Future commitments, due in 2019	106	'
Rail Transportation Commitments [Member]	'	'
Long-term Purchase Commitment [Line Items]	'	'
Future commitment, end date	'2014-06	'
Future commitment, total	10	'
Cost Sharing Commitment [Member]	'	'
Long-term Purchase Commitment [Line Items]	'	'
Future commitment, total	25	'
Future commitment, due in 2014	15	'
Future commitment, due in 2015	8	'
Future commitment, due in 2016	$2	'

Related_Party_Transactions_Add

Related Party Transactions - Additional Information (Detail) (USD $)

12 Months Ended

1 Months Ended

12 Months Ended

12 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Sep. 30, 2012

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2013

Mar. 27, 2012

Aug. 31, 2012

Aug. 31, 2012

Dec. 31, 2013

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Dec. 31, 2011

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Officers And Other Key Employees [Member]

Officers And Other Key Employees [Member]

Officers And Other Key Employees [Member]

Other Affiliates [Member]

Wheatland Oil Inc. [Member]

Wheatland Oil Inc. [Member]

Wheatland Oil Inc. [Member]

Non-operational Pipeline Transportation Commitments[Member]

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

Affiliate [Member]

bbl

bbl

bbl

bbl

Chief Executive Officer [Member]

Vice Chairman [Member]

Affiliate [Member]

Related Party Transaction [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Revenues from transactions with related party

$105,108,000

$63,593,000

$93,790,000

'

'

$1,900,000

$41,700,000

$1,300,000

$38,500,000

$67,500,000

'

'

'

'

'

'

'

'

$61,700,000

$53,500,000

Due from affiliates

12,700,000

11,700,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of barrels sold to affiliate

'

'

'

'

'

21,000

435,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of barrels purchased from affiliate

'

'

'

'

30,000

2,000

0

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchases from transactions with related party

'

'

'

'

3,000,000

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expenses from transactions with related party

700,000

'

1,000,000

'

2,200,000

2,700,000

1,400,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Accounts payable to affiliates

200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Capitalized costs

'

'

'

'

5,700,000

5,000,000

4,100,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Production expenses to affiliates

6,111,000

6,675,000

4,632,000

'

1,400,000

2,000,000

4,600,000

'

'

'

'

'

'

'

'

4,700,000

4,700,000

4,600,000

'

'

Total amount paid to related party

48,500,000

32,700,000

30,800,000

'

'

'

'

0

277,000

4,900

238,000

'

'

'

'

'

'

'

'

'

Due to affiliates

5,100,000

5,600,000

'

'

'

'

'

200,000

300,000

'

'

'

'

'

'

'

'

'

'

'

Revenues paid to related party

'

'

'

'

'

'

'

2,300,000

38,300,000

46,800,000

'

'

'

'

'

'

'

'

'

'

Due from affiliates

'

'

'

'

'

'

'

400,000

700,000

'

'

'

'

'

'

'

'

'

'

'

Amount charged to affiliate for aircraft use

55,000

112,000

235,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total amount received from related party

'

'

'

'

'

'

'

'

'

'

379,000

'

'

'

'

'

'

'

'

'

Amount charged to company by affiliate for aircraft use

51,000

102,000

88,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Related Party Transaction Transportation Contract Period

'

'

'

'5 years

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

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

'

'

'

'

'

CEO ownership in related party

'

'

'

'

'

'

'

'

'

'

'

75.00%

75.00%

'

'

'

'

'

'

'

Vice Chairman ownership in related party

'

'

'

'

'

'

'

'

'

'

'

'

'

25.00%

'

'

'

'

'

'

Stock_Based_Compensation_Assoc

Stock Based Compensation - Associated Compensation Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'	'	'
Non-cash equity compensation	$39,890	$29,057	$16,572

StockBased_Compensation_Additi

Stock-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Total intrinsic value of options exercised	$7.60	$1.10	'
Common stock available for issue	9,840,036	'	'
Restricted stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Fair value at vesting date	49.4	33	19.9
Unrecognized compensation expense related to non-vested	$55	'	'
Unrecognized compensation expense related to non-vested, period for recognition, in years	'1 year 6 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	7,500,000	'	'
2013 Plan [Member] | Restricted stock [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Stock available to grant	9,813,989	'	'
2005 Plan [Member]	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'
Common stock available for issue	1,840,036	'	'
Shares available for issuance to be forfeited or withheld for payment of taxes	500,000	'	'

Stock_Based_Compensation_Sched

Stock Based Compensation - Schedule of Stock Option Activity (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]	'	'
Number of stock options, Outstanding, Beginning of period	86,500	104,970
Number of stock options, Outstanding, Exercised	-86,500	-18,470
Number of stock options, Outstanding, End of period	0	86,500
Weighted average exercise price, Outstanding, Beginning of period	$0.71	$0.71
Weighted average exercise price, Outstanding, Exercised	$0.71	$0.71
Weighted average exercise price, Outstanding, End of period	$0	$0.71
Number of stock options, Exercisable, Beginning of period	86,500	104,970
Number of stock options, Exercisable, End of period	0	86,500
Weighted average exercise price, Exercisable, Beginning of period	$0.71	$0.71
Weighted average exercise price, Exercisable, End of period	$0	$0.71

Stock_Based_Compensation_Summa

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
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	1,629,462	1,198,344	1,108,077
Granted shares	261,259	916,028	491,315
Vested shares	-464,809	-444,723	-359,601
Forfeited shares	-68,756	-40,187	-41,447
Non-vested shares, ending balance	1,357,156	1,629,462	1,198,344
Non-vested, weighted average grant-date fair value, beginning of period	$63.28	$48.66	$35.72
Granted, weighted average grant-date fair value	$97.95	$73.46	$63.59
Vested, weighted average grant-date fair value	$47.30	$45.25	$29.95
Forfeited, weighted average grant-date fair value	$71.91	$59.05	$41.93
Non-vested, weighted average grant-date fair value, end of period	$74.99	$63.28	$48.66

Property_Acquisition_and_Dispo

Property Acquisition and Dispositions - Additional Information (Detail) (USD $)

12 Months Ended

1 Months Ended

1 Months Ended

Dec. 31, 2013

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2012

Feb. 29, 2012

Dec. 31, 2012

Feb. 29, 2012

Dec. 31, 2012

Feb. 29, 2012

Feb. 29, 2012

Dec. 31, 2012

Dec. 31, 2011

North Dakota [Member]

North Dakota [Member]

North Dakota [Member]

North Dakota [Member]

North Dakota [Member]

North Dakota [Member]

Wyoming [Member]

Oklahoma [Member]

Total of Michigan, North Dakota and Montana [Member]

acre

acre

Producing Properties [Member]

Producing Properties [Member]

Producing properties [Member]

Producing properties [Member]

Boe

Boe

Property Acquisition And Dispositions [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

Acquired producing and undeveloped properties in cash

$563,485,000

$1,484,016,000

$248,562,000

$663,300,000

$276,000,000

'

'

$477,100,000

$51,700,000

'

'

'

Acres acquired

'

'

'

119,000

23,100

'

'

'

'

'

'

'

Daily production of acquired producing properties, barrels of oil per day

'

'

'

'

'

6,500

1,000

'

'

'

'

'

Acquisitions and disposals proceeds

'

126,400,000

'

'

'

'

'

'

'

84,400,000

15,900,000

30,200,000

Recognized pre-tax gain

'

68,000,000

'

'

'

'

'

'

'

50,100,000

15,900,000

21,400,000

Asset retirement obligations for disposed properties

'

$8,300,000

'

'

'

'

'

'

'

$11,100,000

$600,000

'

Property_Transaction_with_Rela1

Property Transaction with Related Party - Additional Information (Detail) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2013	Mar. 27, 2012	Dec. 31, 2012	Dec. 31, 2012
	MBoe		Wheatland Oil Inc. [Member]	Wheatland [Member]	Oil And Natural Gas [Member]
Related Party Transaction [Line Items]	'	'	'	'	'
CEO ownership in related party	'	'	75.00%	'	'
Vice Chairman ownership in related party	'	'	25.00%	'	'
Issuance of common stock to acquire property, in shares	3.9	'	'	'	'
Common stock par value per share	$0.01	$0.01	'	'	'
Consideration cost	$279	'	'	'	'
Purchase price adjustments arising after the closing date as allowed	'	0.5	'	'	'
Net book value	'	'	'	82	177
Joint interest obligations	'	'	'	'	38
Asset retirement obligations	0.6	'	'	'	'
Deferred income tax liabilities	57	'	'	'	'
Crude oil and natural gas production	484	'	'	'	'
Crude oil and natural gas revenues	$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, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'	'
Crude oil and natural gas sales	$3,606,774	$2,379,433	$1,647,419
Production expenses	-282,197	-195,440	-138,236
Production taxes and other expenses	-332,130	-228,438	-144,810
Exploration Expense	-34,947	-23,507	-27,920
Depreciation, depletion, amortization and accretion	-953,796	-683,207	-384,301
Property impairments	-220,508	-122,274	-108,458
Income taxes	-659,783	-428,095	-321,447
Results from crude oil and natural gas producing activities	$1,123,413	$698,472	$522,247

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'	'
Property Acquisition Costs - Proved	$16,604	$738,415	$65,315
Property Acquisition Costs - Unproved	546,881	745,601	183,247
Total property acquisition costs	563,485	1,484,016	248,562
Exploration Costs	687,767	857,681	734,797
Development Costs	2,549,203	1,975,660	1,178,136
Total	$3,800,455	$4,317,357	$2,161,495

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'	'
Exploration costs included in asset retirement costs	$1.80	$3.30	$1.70
Development costs included in asset retirement costs	$6	$1	$3.70

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, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Oil and Gas Exploration and Production Industries Disclosures [Abstract]	'	'
Proved crude oil and natural gas properties	$12,423,878	$8,980,505
Unproved crude oil and natural gas properties	1,181,268	1,073,944
Total	13,605,146	10,054,449
Less accumulated depreciation, depletion and amortization	-3,083,180	-2,090,845
Net capitalized costs	$10,521,966	$7,963,604

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
In Thousands, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	Well	Well	Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]	'	'	'
Balance at January 1	$92,699	$128,123	$92,806
Additions to capitalized exploratory well costs pending determination of proved reserves	548,933	485,530	500,046
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	-479,507	-520,187	-456,780
Capitalized exploratory well costs charged to expense	-9,350	-767	-7,949
Balance at December 31	$152,775	$92,699	$128,123
Number of wells	67	46	56

Supplemental_Crude_Oil_and_Nat2

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBoe	MBoe	MBoe
Reserve Quantities [Line Items]	'	'	'
Percentage of discounted future net cash flows	99.00%	99.00%	96.00%
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	94.00%	'	'
Growth plan to drilling programs period	'5 years	'	'
Revisions of previous estimates	-96,054	4,149	2,237
Extensions, discoveries and other additions	444,654	233,652	161,981
Discount factor utilized as standardized measure for future net cash flows	10.00%	'	'
Crude Oil [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-55,783	33,272	28,607
Extensions, discoveries and other additions	267,009	166,844	87,465
Weighted average price utilized in computation of future cash inflows	91.5	86.56	88.71
Natural Gas [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	-241,623	-174,736	-158,219
Extensions, discoveries and other additions	1,065,870	400,848	447,098
Weighted average price utilized in computation of future cash inflows	5.36	4.31	5.59
Bakken [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Revisions of previous estimates	42,000	'	'
Revisions of previous estimates	81,000	'	'
Extensions, discoveries and other additions	227,000	'	'
Extensions, discoveries and other additions	276,000	'	'
SCOOP [Member]	'	'	'
Reserve Quantities [Line Items]	'	'	'
Extensions, discoveries and other additions	36,000	'	'
Extensions, discoveries and other additions	158,000	'	'

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, 2013	Dec. 31, 2012	Dec. 31, 2011
	MBoe	MBoe	MBoe
Changes in Proved Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period, Total	784,677	508,438	364,712
Revisions of previous estimates, Total	-96,054	4,149	2,237
Extensions, discoveries and other additions, Total	444,654	233,652	161,981
Production, Total	-49,610	-35,716	-22,581
Sales of minerals in place, Total	0	-7,838	0
Purchases of minerals in place, Total	458	81,992	2,089
Proved reserves at end of period, Total	1,084,125	784,677	508,438
Crude Oil [Member]	'	'	'
Changes in Proved Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period	561,163	326,133	224,784
Revisions of previous estimates	-55,783	33,272	28,607
Extensions, discoveries and other additions	267,009	166,844	87,465
Production	-34,989	-25,070	-16,469
Sales of minerals in place	0	-7,165	0
Purchases of minerals in place	388	67,149	1,746
Proved reserves at end of period	737,788	561,163	326,133
Natural Gas [Member]	'	'	'
Changes in Proved Reserves [Roll Forward]	'	'	'
Proved reserves at beginning of period	1,341,084	1,093,832	839,568
Revisions of previous estimates	-241,623	-174,736	-158,219
Extensions, discoveries and other additions	1,065,870	400,848	447,098
Production	-87,730	-63,875	-36,671
Sales of minerals in place	0	-4,046	0
Purchases of minerals in place	419	89,061	2,056
Proved reserves at end of period	2,078,020	1,341,084	1,093,832

Supplemental_Crude_Oil_and_Nat4

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
	MBbls	MBbls	MBbls	MBbls
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed Reserves (MBOE)	406,792	317,786	205,235	'
Proved Undeveloped Reserve (MBOE)	677,333	466,891	303,203	'
Total Proved Reserves (MBOE)	1,084,125	784,677	508,438	'
Crude Oil [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed Reserves (Volume)	278,630	226,870	145,024	'
Proved Undeveloped Reserve (Volume)	459,158	334,293	181,109	'
Total Proved Reserves (Volume)	737,788	561,163	326,133	224,784
Natural Gas [Member]	'	'	'	'
Reserve Quantities [Line Items]	'	'	'	'
Proved Developed Reserves (Volume)	768,969	545,499	361,265	'
Proved Undeveloped Reserve (Volume)	1,309,051	795,585	732,567	'
Total Proved Reserves (Volume)	2,078,020	1,341,084	1,093,832	839,568

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Crude Oil and Natural Gas Information [Abstract]	'	'	'
Future cash inflows	$78,646,274	$54,362,574	$35,042,916
Future production costs	-21,333,460	-13,103,469	-7,495,552
Future development and abandonment costs	-10,250,789	-8,295,130	-5,073,043
Future income taxes	-12,447,127	-8,500,766	-5,956,615
Future net cash flows	34,614,898	24,463,209	16,517,706
10% annual discount for estimated timing of cash flows	-18,319,131	-13,282,852	-9,012,350
Standardized measure of discounted future net cash flows	$16,295,767	$11,180,357	$7,505,356

Supplemental_Crude_Oil_and_Nat6

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Parenthetical) (Detail)	12 Months Ended
	Dec. 31, 2013
Supplemental Crude Oil and Natural Gas Information [Abstract]	'
Discount factor utilized as standardized measure for future net cash flows	10.00%

Supplemental_Crude_Oil_and_Nat7

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, 2013	Dec. 31, 2012	Dec. 31, 2011
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flow Relating to Proved Oil and Gas Reserves [Roll Forward]	'	'	'
Standardized measure of discounted future net cash flows at beginning of year	$11,180,357	$7,505,356	$3,785,322
Extensions, discoveries and improved recoveries, less related costs	6,613,665	3,724,136	2,276,355
Revisions of previous quantity estimates	-1,765,300	254,493	133,990
Changes in estimated future development and abandonment costs	1,942,585	-298,148	-70,219
Purchases (sales) of minerals in place	12,012	1,171,047	56,246
Net change in prices and production costs	263,541	-530,515	1,855,532
Accretion of discount	1,118,036	750,536	378,532
Sales of crude oil and natural gas produced, net of production costs	-2,992,447	-1,955,555	-1,364,373
Development costs incurred during the period	1,210,223	1,095,156	528,737
Change in timing of estimated future production and other	464,111	-102,519	773,279
Change in income taxes	-1,751,016	-433,630	-848,045
Net change	5,115,410	3,675,001	3,720,034
Standardized measure of discounted future net cash flows at end of year	$16,295,767	$11,180,357	$7,505,356

Quarterly_Financial_Data_Sched

Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) (USD $)	3 Months Ended																12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2013		Sep. 30, 2013		Jun. 30, 2013		Mar. 31, 2013		Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Information Disclosure [Abstract]	'		'		'		'		'		'		'		'		'	'	'
Total revenues	$820,334	[1]	$823,835	[1]	$1,100,752	[1]	$710,229	[1]	$688,972	[1]	$483,729	[1]	$1,004,719	[1]	$395,100	[1]	$3,455,150	$2,572,520	$1,649,789
Gain (loss) on derivative instruments, net	-102,202	[1]	-203,774	[1]	199,056	[1]	-84,831	[1]	9,639	[1]	-158,294	[1]	471,728	[1]	-169,057	[1]	-191,751	154,016	-30,049
Income from operations	273,706		328,043		573,872		270,146		365,220		105,522		686,474		135,591		1,445,767	1,292,807	760,752
Net income	$132,824		$167,498		$323,270		$140,627		$220,511		$44,096		$405,684		$69,094		$764,219	$739,385	$429,072
Net income per share: Basic	$0.72		$0.91		$1.76		$0.76		$1.20		$0.24		$2.26		$0.38		$4.15	$4.08	$2.42
Net income per share: Diluted	$0.72		$0.91		$1.75		$0.76		$1.19		$0.24		$2.25		$0.38		$4.13	$4.07	$2.41
[1]	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of 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.