Continental Resources Inc (CLR) 10-K 24 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 16, 2016	Jun. 30, 2015
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	CLR
Entity Registrant Name	CONTINENTAL RESOURCES, INC
Entity Central Index Key	732,834
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		372,684,421
Entity Public Float			$ 4.9

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 11,463	$ 24,381
Receivables:
Crude oil and natural gas sales	378,622	552,476
Affiliated parties	122	13,360
Joint interest and other, net	232,293	567,476
Derivative assets	93,922	52,423
Inventories	94,151	102,179
Prepaid Taxes	94	63,266
Prepaid expenses and other	11,672	14,040
Total current assets	822,339	1,389,601
Net property and equipment, based on successful efforts method of accounting	14,063,328	13,635,852
Noncurrent derivative assets	14,560	31,992
Other noncurrent assets	19,581	18,588
Total assets	14,919,808	15,076,033
Current liabilities:
Accounts payable trade	553,285	1,263,724
Revenues and royalties payable	187,000	272,755
Payables to affiliated parties	69	7,305
Accrued liabilities and other	176,947	259,157
Derivative liabilities	3,583	1,645
Current portion of long-term debt	2,144	2,078
Total current liabilities	923,028	1,806,664
Long-term debt, net of current portion	7,115,644	5,926,800
Other noncurrent liabilities:
Deferred income tax liabilities, net	2,090,228	2,286,796
Asset retirement obligations, net of current portion	101,251	75,462
Noncurrent derivative liabilities	3,706	3,109
Other noncurrent liabilities	17,051	9,358
Total other noncurrent liabilities	$ 2,212,236	$ 2,374,725
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; 1,000,000,000 shares authorized; 372,959,080 shares issued and outstanding at December 31, 2015; 372,005,502 shares issued and outstanding at December 31, 2014	3,730	3,720
Additional paid-in capital	1,345,624	1,287,941
Accumulated other comprehensive loss	(3,354)	(385)
Retained earnings	3,322,900	3,676,568
Total shareholders’ equity	4,668,900	4,967,844
Total liabilities and shareholders’ equity	$ 14,919,808	$ 15,076,033

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Preferred stock, par value	$ 0.01	$ 0.01
Preferred stock, shares authorized	25,000,000	25,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	500,000,000
Common stock, shares issued	372,959,080	372,005,502
Common stock, outstanding	372,959,080	372,005,502

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues:
Crude oil and natural gas sales	$ 2,551,131	$ 4,107,894	$ 3,473,026
Crude oil and natural gas sales to affiliates	1,400	95,128	100,405
Gain (loss) on derivative instruments, net	91,085	559,759	(191,751)
Crude oil and natural gas service operations	36,551	38,837	40,127
Total revenues	2,680,167	4,801,618	3,421,807
Operating costs and expenses:
Production expenses	347,243	347,349	280,789
Production expenses to affiliates	1,654	5,123	1,408
Production taxes and other expenses	200,637	349,760	298,787
Exploration expenses	19,413	50,067	34,947
Crude oil and natural gas service operations	17,337	21,871	29,665
Depreciation, depletion, amortization and accretion	1,749,056	1,358,669	965,645
Property impairments	402,131	616,888	220,508
General and administrative expenses	189,846	184,655	144,379
Gain on sale of assets, net	(23,149)	(600)	(88)
Total operating costs and expenses	2,904,168	2,933,782	1,976,040
Income (loss) from operations	(224,001)	1,867,836	1,445,767
Other income (expense):
Interest expense	(313,079)	(283,928)	(235,275)
Loss on extinguishment of debt	0	(24,517)	0
Other	1,995	2,647	2,557
Total other income (expense)	(311,084)	(305,798)	(232,718)
Income (loss) before income taxes	(535,085)	1,562,038	1,213,049
Provision (benefit) for income taxes	(181,417)	584,697	448,830
Net income (loss)	$ (353,668)	$ 977,341	$ 764,219
Basic net income per share (in dollars per share)	$ (0.96)	$ 2.65	$ 2.08
Diluted net income per share (in dollars per share)	$ (0.96)	$ 2.64	$ 2.07
Foreign currency translation adjustments	$ (2,969)	$ (385)	$ 0
Other Comprehensive Income (Loss), Net of Tax	(2,969)	(385)	0
Comprehensive Income (Loss), Net of Tax	$ (356,637)	$ 976,956	$ 764,219

Consolidated Statements of Shar

Consolidated Statements of Shareholders' Equity - USD ($) $ in Thousands	Total	Common stock	Additional paid-in capital	Accumulated Other Comprehensive Income (Loss)	Retained earnings
Balance at Dec. 31, 2012	$ 3,163,699	$ 3,712	$ 1,224,979		$ 1,935,008
Balance, shares at Dec. 31, 2012		371,209,362
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	764,219				764,219
Other Comprehensive Income (Loss), Net of Tax	0
Stock-based compensation	39,886		39,886
Restricted stock:
Issued	5	$ 5	0
Issued, shares		522,518
Repurchased and canceled	(14,690)	$ (3)	(14,687)
Repurchased and canceled, shares		(277,050)
Forfeited	(1)	$ (1)
Forfeited, shares		(137,512)
Balance at Dec. 31, 2013	3,953,118	$ 3,713	1,250,178		2,699,227
Balance, shares at Dec. 31, 2013		371,317,318
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	977,341				977,341
Other Comprehensive Income (Loss), Net of Tax	(385)			$ (385)
Stock-based compensation	54,343		54,343
Restricted stock:
Issued	14	$ 14	0
Issued, shares		1,424,764
Repurchased and canceled	(16,583)	$ (3)	(16,580)
Repurchased and canceled, shares		(283,434)
Forfeited	(4)	$ (4)
Forfeited, shares		(453,146)
Balance at Dec. 31, 2014	$ 4,967,844	$ 3,720	1,287,941	(385)	3,676,568
Balance, shares at Dec. 31, 2014	372,005,502	372,005,502
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ (353,668)				(353,668)
Other Comprehensive Income (Loss), Net of Tax	(2,969)			(2,969)
Stock-based compensation	51,817		51,817
Excess Tax Benefit from Share-based Compensation	13,177		13,177
Restricted stock:
Issued	15	$ 15	0
Issued, shares		1,462,534
Repurchased and canceled	(7,313)	$ (2)	(7,311)
Repurchased and canceled, shares		(172,786)
Forfeited	(3)	$ (3)
Forfeited, shares		(336,170)
Balance at Dec. 31, 2015	$ 4,668,900	$ 3,730	$ 1,345,624	$ (3,354)	$ 3,322,900
Balance, shares at Dec. 31, 2015	372,959,080	372,959,080

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities:
Net income (loss)	$ (353,668)	$ 977,341	$ 764,219
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,746,454	1,368,311	965,437
Property impairments	402,131	616,888	220,508
Non-cash (gain) loss on derivatives, net	(21,532)	(174,409)	130,196
Stock-based compensation	51,834	54,353	39,890
Provision (benefit) for deferred income taxes	(181,441)	584,677	442,621
Excess tax benefit from stock-based compensation	(13,177)	0	0
Dry hole costs	8,381	23,679	9,350
Gain on sale of assets, net	(23,149)	(600)	(88)
Loss on extinguishment of debt	0	24,517	0
Other, net	12,646	7,637	2,037
Changes in assets and liabilities:
Accounts receivable	524,973	(129,634)	(166,138)
Inventories	7,997	(65,919)	(7,697)
Other current assets	65,493	(57,489)	(11,537)
Accounts payable trade	(201,434)	85,540	107,250
Revenues and royalties payable	(85,754)	(18,022)	28,401
Accrued liabilities and other	(84,056)	58,880	44,260
Other noncurrent assets and liabilities	1,403	(35)	(5,414)
Net cash provided by operating activities	1,857,101	3,355,715	2,563,295
Cash flows from investing activities:
Exploration and development	(3,042,747)	(4,604,468)	(3,660,773)
Purchase of producing crude oil and natural gas properties	(557)	(48,917)	(16,604)
Purchase of other property and equipment	(36,951)	(63,402)	(62,054)
Proceeds from sale of assets and other	34,008	129,388	28,420
Net cash used in investing activities	(3,046,247)	(4,587,399)	(3,711,011)
Cash flows from financing activities:
Credit facility borrowings	2,001,000	1,695,000	970,000
Repayment of credit facility	(1,313,000)	(1,805,000)	(1,290,000)
Proceeds from issuance of Senior Notes	0	1,681,834	1,479,375
Redemption of Senior Notes	0	(300,000)	0
Premium on redemption of Senior Notes	0	(17,497)	0
Proceeds from other debt	500,000	0	0
Repayment of other debt	(2,078)	(2,013)	(1,951)
Debt issuance costs	(4,597)	(8,026)	(2,265)
Repurchase of restricted stock for tax withholdings	(7,313)	(16,583)	(14,690)
Excess tax benefit from stock-based compensation	13,177	0	0
Net cash provided by financing activities	1,187,189	1,227,715	1,140,469
Effect of exchange rate on cash and cash equivalents	(10,961)	(132)	0
Net change in cash and cash equivalents	(12,918)	(4,101)	(7,247)
Cash and cash equivalents at beginning of period	24,381	28,482	35,729
Cash and cash equivalents at end of period	$ 11,463	$ 24,381	$ 28,482

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2015
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 primarily located 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 all properties south of Kansas and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately 68% of the Company’s crude oil and natural gas production and approximately 77% of its crude oil and natural gas revenues for the year ended December 31, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2015 , approximately 58% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately 32% of the Company's crude oil and natural gas production, 23% of its crude oil and natural gas revenues, and 42% of its estimated proved reserves at December 31, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2015 , crude oil accounted for approximately 66% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 57% of the Company's estimated proved reserves as of December 31, 2015 . 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. 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, 2015 and 2014 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, 2015 , the Company had cash deposits in excess of federally insured amounts of approximately $10.7 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area. Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material. Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2015 , sales to the Company’s largest purchaser accounted for approximately 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2015 . 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 various regions. Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179 Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations. Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering systems; storage tanks; office and computer equipment, software, furniture and fixtures; 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 Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40 Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates. Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs on its crude oil and natural gas properties and related facilities disposal. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2013 through December 31, 2015 : In thousands 2015 2014 2013 Asset retirement obligations at January 1 $ 76,708 $ 55,787 $ 47,171 Accretion expense 4,740 3,366 2,767 Revisions (1) 15,068 9,916 2,826 Plus: Additions for new assets 7,404 9,022 6,009 Less: Plugging costs and sold assets (1,011 ) (1,383 ) (2,986 ) Total asset retirement obligations at December 31 $ 102,909 $ 76,708 $ 55,787 Less: Current portion of asset retirement obligations at December 31 (2) 1,658 1,246 1,434 Non-current portion of asset retirement obligations at December 31 $ 101,251 $ 75,462 $ 54,353 (1) Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties. (2) Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets. As of December 31, 2015 and 2014 , net property and equipment on the consolidated balance sheets included $87.5 million and $64.7 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. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties 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 drilling plans, 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 three-year term loan, note payable, and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method. The Company had capitalized costs of $71.8 million and $76.1 million (net of accumulated amortization of $47.0 million and $38.1 million ) relating to its long-term debt at December 31, 2015 and 2014 , respectively. See the subsequent heading titled New accounting pronouncements for a discussion of the presentation of these costs on the consolidated balance sheets. For the years ended December 31, 2015 , 2014 and 2013 , the Company recognized amortization expense associated with capitalized debt issuance costs of $8.9 million , $9.3 million and $8.6 million , respectively, which are reflected in “Interest expense” in the consolidated statements of comprehensive income (loss). 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 contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2015 and 2014 . 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. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. 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 recorded valuation allowances of $13.5 million and $4.4 million for the years ended December 31, 2015 and 2014, respectively, against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company does not expect to realize a benefit. Earnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method. The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands, except per share data 2015 2014 2013 Income (loss) (numerator): Net income (loss) - basic and diluted $ (353,668 ) $ 977,341 $ 764,219 Weighted average shares (denominator): Weighted average shares - basic 369,540 368,829 368,150 Non-vested restricted stock (1) — 1,929 1,548 Weighted average shares - diluted 369,540 370,758 369,698 Net income (loss) per share: Basic $ (0.96 ) $ 2.65 $ 2.08 Diluted $ (0.96 ) $ 2.64 $ 2.07 (1) During the year ended December 31, 2015 , the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations. Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. New accounting pronouncements In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes, three-year term loan and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of December 31, 2015 , inclusive of costs incurred upon execution of the Company's new term loan in November 2015 as discussed in Note 7. Long-Term Debt . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $7.8 million and $7.0 million as of December 31, 2015 and 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the consolidated balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which requires entities with a classified balance sheet to present all deferred tax assets and deferred tax liabilities as noncurrent instead of separating deferred taxes into current and noncurrent amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company early adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
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 tax payments and refunds. 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 2015 2014 2013 Supplemental cash flow information: Cash paid for interest $ 301,743 $ 267,384 $ 209,815 Cash paid for income taxes 30 53,457 29,017 Cash received for income tax refunds 61,403 7 174 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (519,949 ) 290,782 89,482 Asset retirement obligation additions and revisions, net 22,472 18,938 8,835

Net Property and Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Service properties, equipment and other 307,059 274,584 Total property and equipment 20,510,771 18,286,631 Accumulated depreciation, depletion and amortization (6,447,443 ) (4,650,779 ) Net property and equipment $ 14,063,328 $ 13,635,852

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Prepaid advances from joint interest owners $ 49,917 $ 115,687 Accrued compensation 40,060 39,848 Accrued production taxes, ad valorem taxes and other non-income taxes 21,678 36,550 Accrued interest 62,058 60,861 Current portion of asset retirement obligations 1,658 1,246 Other 1,576 4,965 Accrued liabilities and other $ 176,947 $ 259,157

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments The Company recognizes all derivative instruments on the balance sheet as either assets or liabilities measured at fair value. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.” The Company may utilize swap and collar derivative contracts to economically hedge against the variability in cash flows associated with the 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, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. 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 Inter-Continental Exchange ("ICE") pricing for Brent crude oil and natural gas derivative settlements based on NYMEX Henry Hub pricing. The estimated fair value of derivative contracts is based upon various factors, including commodity exchange prices, over-the-counter quotations, and, in the case of collars and written call options, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars and written call options requires the use of an option-pricing model. See Note 6. Fair Value Measurements . At December 31, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts that have varying durations and may not be realized on a ratable basis over a calendar year. Crude Oil - ICE Brent Period and Type of Contract Bbls Ceiling Price January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price. Natural Gas - Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2016 - December 2016 Swaps - Henry Hub 133,710,000 $ 3.17 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08 Derivative gains and losses The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Year ended December 31, In thousands 2015 2014 2013 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ 331,591 $ (54,289 ) Crude oil collars (1) — 65,310 (16,867 ) Natural gas fixed price swaps 39,670 (11,551 ) 9,601 Natural gas collars 29,883 — — Cash received (paid) on derivatives, net 69,553 385,350 (61,555 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 84,792 (117,580 ) Crude oil collars — 1,121 (8,587 ) Crude oil written call options 4,715 3,981 — Natural gas fixed price swaps 41,828 62,699 (4,029 ) Natural gas collars (25,011 ) 21,816 — Non-cash gain (loss) on derivatives, net 21,532 174,409 (130,196 ) Gain (loss) on derivative instruments, net $ 91,085 $ 559,759 $ (191,751 ) (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations. Balance sheet offsetting of derivative assets and liabilities The Company’s derivative contracts are recorded at 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 table present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2015 2014 Commodity derivative assets: Gross amounts of recognized assets $ 120,385 $ 84,431 Gross amounts offset on balance sheet (11,903 ) (16 ) Net amounts of assets on balance sheet 108,482 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (19,192 ) (4,770 ) Gross amounts offset on balance sheet 11,903 16 Net amounts of liabilities on balance sheet $ (7,289 ) $ (4,754 ) The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2015 2014 Derivative assets $ 93,922 $ 52,423 Noncurrent derivative assets 14,560 31,992 Net amounts of assets on balance sheet 108,482 84,415 Derivative liabilities (3,583 ) (1,645 ) Noncurrent derivative liabilities (3,706 ) (3,109 ) Net amounts of liabilities on balance sheet (7,289 ) (4,754 ) Total derivative assets, net $ 101,193 $ 79,661

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements The Company follows a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: • Level 1: Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. • Level 2: Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. • Level 3: Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value. A financial instrument’s categorization within the hierarchy is based upon the lowest level of input that is significant to the fair value measurement. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the hierarchy. As Level 1 inputs generally provide the most reliable evidence of fair value, the Company uses Level 1 inputs when available. The Company’s policy is to recognize transfers between the hierarchy levels as of the beginning of the reporting period in which the event or change in circumstances caused the transfer. Assets and liabilities measured at fair value on a recurring basis The Company's derivative instruments are reported at fair value on a recurring basis. In determining the fair values of fixed price swaps, a discounted cash flow method is used due to the unavailability of relevant comparable market data for the Company’s exact contracts. The discounted cash flow method estimates future cash flows based on quoted market prices for forward commodity prices and a risk-adjusted discount rate. The fair values of fixed price swaps are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars and written call options requires the use of an industry-standard option pricing model that considers various inputs including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. These assumptions are observable in the marketplace or can be corroborated by active markets or broker quotes and are therefore designated as Level 2 within the valuation hierarchy. The Company’s calculation of fair value for each of its derivative positions is compared to the counterparty valuation for reasonableness. The following tables summarize the valuation of financial instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 . Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) — (38 ) Total $ — $ 101,193 $ — $ 101,193 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) $ — (4,754 ) Total $ — $ 79,661 $ — $ 79,661 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. 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 the Company's estimates of future crude oil and natural gas production, commodity prices based on commodity futures price strips, operating 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 2020 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 34 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 $138.9 million for the year ended December 31, 2015 resulting from declines in commodity prices that indicated the carrying amounts for certain fields were not recoverable. The 2015 impairments reflect fair value adjustments primarily concentrated in an emerging area with minimal production and costly reserve additions ( $42.5 million ), the Medicine Pole Hills units ( $32.5 million ), the Buffalo Red River units ( $26.3 million ), non-Bakken areas of North Dakota and Montana ( $8.2 million ), Wyoming properties ( $17.9 million ), and various legacy areas in the South region ( $11.4 million ). The impaired properties were written down to their estimated fair value totaling approximately $59.9 million . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2015 , 2014 , and 2013 , reflecting recurring amortization of undeveloped leasehold costs on properties the Company expects will not be transferred to proved properties over the lives of the leases based on drilling plans, experience of successful drilling, and the average holding period. The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2015 2014 2013 Proved property impairments $ 138,878 $ 324,302 $ 51,805 Unproved property impairments 263,253 292,586 168,703 Total $ 402,131 $ 616,888 $ 220,508 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, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 853,000 $ 853,000 $ 165,000 $ 165,000 Term loan 498,274 500,000 — — Note payable 14,309 12,500 16,375 14,900 7.375% Senior Notes due 2020 196,574 179,200 195,997 213,000 7.125% Senior Notes due 2021 395,365 388,300 394,668 421,000 5% Senior Notes due 2022 1,996,831 1,480,400 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,482,451 1,061,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,932 700,300 988,940 868,700 4.9% Senior Notes due 2044 691,052 430,500 690,912 572,400 Total debt $ 7,117,788 $ 5,605,200 $ 5,928,878 $ 5,485,700 The fair values of credit facility borrowings and the term loan approximate carrying value based on borrowing rates available to the Company for bank loans with similar terms and maturities and are 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 7.375% Senior Notes due 2020 (“2020 Notes”), the 7.125% Senior Notes due 2021 (“2021 Notes”), the 5% Senior Notes due 2022 (“2022 Notes”), the 4.5% Senior Notes due 2023 (“2023 Notes”), the 3.8% Senior Notes due 2024 (“2024 Notes”), and the 4.9% Senior Notes due 2044 (“2044 Notes”) are based on quoted market prices and, accordingly, are classified as Level 1 in the fair value hierarchy. The carrying values of all classes of cash and cash equivalents, trade receivables, and trade payables are considered to be representative of their respective fair values due to the short term maturities of those instruments.

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.6 million and $52.6 million at December 31, 2015 and 2014 , respectively, consists of the following. See Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. December 31, In thousands 2015 2014 Credit facility $ 853,000 $ 165,000 Term loan 498,274 — Note payable 14,309 16,375 7.375% Senior Notes due 2020 196,574 195,997 7.125% Senior Notes due 2021 395,365 394,668 5% Senior Notes due 2022 1,996,831 1,996,507 4.5% Senior Notes due 2023 1,482,451 1,480,479 3.8% Senior Notes due 2024 989,932 988,940 4.9% Senior Notes due 2044 691,052 690,912 Total debt 7,117,788 5,928,878 Less: Current portion of long-term debt 2,144 2,078 Long-term debt, net of current portion $ 7,115,644 $ 5,926,800 Revolving credit facility The Company has an unsecured revolving credit facility, maturing on May 16, 2019, with aggregate commitments totaling $2.75 billion at December 31, 2015 , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. The Company had $853 million and $165 million of outstanding borrowings on its credit facility at December 31, 2015 and 2014 , respectively. Borrowings bear interest at market-based interest rates plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The weighted-average interest rate on outstanding borrowings at December 31, 2015 was 1.9% . The Company had approximately $1.9 billion of borrowing availability on its credit facility at December 31, 2015 and incurred commitment fees based on its assigned credit rating at that date of 0.225% per annum of the daily average amount of unused borrowing availability under its credit facility. The revolving credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (total debt less cash and cash equivalents) divided by the sum of net debt plus total shareholders' equity plus, to the extent resulting in a reduction of total shareholders' equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. The Company was in compliance with this covenant at December 31, 2015 . Senior notes The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series 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 of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption. The Company’s senior notes are not subject to any mandatory redemption or sinking fund requirements. The indentures governing the Company's senior notes contain covenants that, among others, limit the Company's ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, and consolidate, merge or transfer certain assets. The senior note covenants are subject to a number of important exceptions and qualifications. The Company was in compliance with these covenants at December 31, 2015 . Two of the Company’s subsidiaries, Banner Pipeline Company, L.L.C. and CLR Asset Holdings, LLC, which have no material assets or operations, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets and operations are minor, do not guarantee the senior notes. 2014 Redemption of Senior Notes In July 2014, the Company redeemed its then outstanding 8.25% Senior Notes due 2019 ("2019 Notes") using a portion of the proceeds from the May 2014 issuances of 2024 Notes and 2044 Notes. The 2019 Notes were redeemed for $317.5 million , representing a make-whole amount calculated in accordance with the terms of the 2019 Notes and related indenture. The Company recognized a pre-tax loss of $24.5 million related to the redemption, which included the make-whole premium and the write-off of deferred financing costs and unaccreted debt discount and is reflected under the caption “Loss on extinguishment of debt" in the consolidated statements of comprehensive income (loss) for the year ended December 31, 2014 . Term loan In November 2015, the Company borrowed $500 million under a three-year term loan agreement, the proceeds of which were used to repay a portion of the borrowings then outstanding on the Company's revolving credit facility. The term loan matures in full on November 4, 2018 and bears interest at a variable market-based interest rate plus a margin that is based on the terms of the borrowing and the credit ratings assigned to the Company's senior, unsecured, long-term indebtedness. The interest rate on the term loan at December 31, 2015 was 1.8% . The term loan contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.0, consistent with the covenant requirement in the Company's revolving credit facility. The Company was in compliance with this covenant at December 31, 2015 . Note payable In February 2012, 20 Broadway Associates LLC, a 100% owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing note payable secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.1 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets at December 31, 2015 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2015 2014 2013 Current income tax provision: United States federal $ — $ — $ 6,193 Various states 24 20 16 Total current income tax provision 24 20 6,209 Deferred income tax provision (benefit): United States federal (140,578 ) 527,315 403,002 Various states (40,863 ) 57,362 39,619 Total deferred income tax provision (benefit) (181,441 ) 584,677 442,621 Total provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 The provision (benefit) for income taxes differs from the amount computed by applying the United States statutory federal income tax rate to income (loss) before income taxes. The sources and tax effects of the difference are as follows: Year ended December 31, In thousands 2015 2014 2013 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (187,280 ) $ 546,713 $ 424,567 State income taxes, net of federal benefit (16,219 ) 42,169 25,838 Canadian valuation allowance 13,503 4,389 — Effect of differing statutory tax rate in Canada 5,239 (1,900 ) — Other, net 3,340 (6,674 ) (1,575 ) Provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830 The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are reflected in the table below. As discussed in Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements , in November 2015 the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This new standard requires that all deferred tax assets and deferred tax liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new standard was early-adopted by the Company as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. Accordingly, all deferred tax assets and deferred tax liabilities have been reflected as noncurrent and the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. December 31, In thousands 2015 2014 Deferred tax assets United States net operating loss carryforwards 398,024 60,904 Canadian net operating loss carryforwards 17,892 4,899 Alternative minimum tax carryforwards 40,796 38,715 Equity compensation 32,910 22,255 Other 11,048 8,920 Total deferred tax assets 500,670 135,693 Canadian valuation allowance (17,892 ) (4,389 ) Total deferred tax assets, net of valuation allowance 482,778 131,304 Deferred tax liabilities Property and equipment (2,528,125 ) (2,254,343 ) Non-cash gains on derivatives (38,452 ) (30,269 ) Gain on derivative liquidation (4,158 ) (132,356 ) Other (2,271 ) (1,132 ) Total deferred tax liabilities (2,573,006 ) (2,418,100 ) Deferred income tax liabilities, net $ (2,090,228 ) $ (2,286,796 ) As of December 31, 2015 , the Company had federal and state net operating loss carryforwards of $865 million and $2.63 billion , respectively. The federal net operating loss carryforward will begin expiring in 2033. The Oklahoma net operating loss carryforward of $2.12 billion will begin to expire in 2027. The remainder of the state net operating loss carryforwards will begin expiring in 2017. The Company has alternative minimum tax credit carryforwards of $41 million that have no expiration date. Any available statutory depletion carryforwards will be recognized when realized. The Company files income tax returns in the U.S. federal, U.S. state and Canadian jurisdictions. With few exceptions, the Company is no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years prior to 2012. The Company recorded valuation allowances of $13.5 million and $4.4 million against Canadian deferred tax assets for the years ended December 31, 2015 and 2014, respectively, which resulted in a cumulative valuation allowance of $17.9 million as of December 31, 2015 . Our Canadian subsidiary has generated operating loss carryforwards for which we do not believe we will realize a benefit. The amount of deferred tax assets considered realizable, however, could change if our subsidiary generates taxable income.

Lease Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Lease Commitments	Lease Commitments The Company’s operating lease obligations primarily represent leases for surface rentals, office equipment, communication towers, software services, and tanks for storage of hydraulic fracturing fluids. Lease payments associated with operating leases for the years ended December 31, 2015 , 2014 and 2013 were $9.6 million , $8.0 million and $3.0 million , respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2015 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2016 $ 3,348 2017 1,327 2018 979 2019 291 2020 210 Thereafter 3,105 Total obligations $ 9,260

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
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, 2015 . The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets. Drilling commitments – As of December 31, 2015 , the Company had drilling rig contracts with various terms extending to year-end 2019 to ensure rig availability in its key operating areas. Future commitments as of December 31, 2015 total approximately $422 million , of which $200 million is expected to be incurred in 2016, $136 million in 2017, $62 million in 2018, and $24 million in 2019. Pipeline transportation commitments – The Company has entered into firm transportation commitments to guarantee pipeline access capacity on operational crude oil and natural gas pipelines. The commitments, which have varying terms extending as far as 2027, require the Company to pay per-unit transportation charges regardless of the amount of pipeline capacity used. Future commitments remaining as of December 31, 2015 under the operational pipeline transportation arrangements amount to approximately $1.0 billion , of which $215 million is expected to be incurred in 2016, $212 million in 2017, $207 million in 2018, $154 million in 2019, $47 million in 2020, and $170 million thereafter. Further, the Company was a party to a five-year firm transportation commitment (the "Agreement") for a future crude oil pipeline project being considered for development that is not yet operational. The project requires the granting of regulatory approvals and requires additional construction efforts by the counterparty before being completed. The project has faced significant delays and has failed to gain the necessary permits and approvals. As a result of the persistent delays and lack of regulatory approval, the Agreement’s basic assumptions and purpose have become commercially impracticable. Accordingly, in 2015 the Company provided a shipper termination notice pursuant to the Agreement and formally provided the counterparty with the Company’s termination of the Agreement in its entirety. The Company's previously disclosed commitments under the Agreement totaled approximately $260 million , which are no longer expected to be incurred. The Company’s pipeline commitments are for production primarily in the North region. The Company is not committed under these contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. Fuel purchase commitment – The Company has entered into a forward purchase contract with a third party to purchase specified quantities of diesel fuel at specified prices each month through June 2016 for use in drilling operations. Over the remaining contract term, the Company has committed to purchase approximately 11 million gallons of diesel fuel at varying prices depending on the grade of diesel fuel purchased and the timing and location of delivery. The contract satisfies a significant portion of the Company's anticipated diesel fuel needs and provides for physical delivery to desired locations. Future commitments under the arrangement as of December 31, 2015 total approximately $31 million , all of which will be incurred in 2016. Litigation – In November 2010, a putative class action was filed in the District Court of Blaine County, Oklahoma by Billy J. Strack and Daniela A. Renner as trustees of certain named trusts and on behalf of other similarly situated parties against the Company. The Petition alleged the Company improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners from crude oil and natural gas wells located in Oklahoma. The plaintiffs 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 proposed class. On November 3, 2014, plaintiffs filed an Amended Petition that did not add any substantive claims, but sought a “hybrid class action” in which they sought certification of certain claims for injunctive relief, reserving the right to seek a further class certification on money damages in the future. Plaintiffs filed an Amended Motion for Class Certification on January 9, 2015, that modified the proposed class to royalty owners in Oklahoma production from July 1, 1993, to the present (instead of 1980 to the present) and sought certification of over 45 separate “issues” for injunctive or declaratory relief, again, reserving the right to seek a further class certification of money damages in the future. The Company responded to the petition, its amendment, and the motions for class certification denying the allegations and raising a number of affirmative defenses and legal arguments to each of the claims and filings. Certain discovery was undertaken and the “hybrid” motion was briefed by plaintiffs and the Company. A hearing on the “hybrid” class certification was held on June 1st and 2nd, 2015. On June 11, 2015, the trial court certified a “hybrid” class as requested by plaintiffs. The Company has appealed the trial court’s class certification order, which will be reviewed de novo by the appellate court. The appeal briefing is complete and ready for determination by the court. An unsuccessful mediation was conducted on December 7, 2015. 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. Although not currently at issue in the “hybrid” certification, plaintiffs have alleged underpayments in excess of $200 million that they may claim as damages, 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 will continue to assert its defenses to the case as certified as well as any future attempt to certify a money damages class. 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, disputes with tax authorities 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, 2015 and 2014 , the Company had recorded a liability on the consolidated balance sheets under the caption “Other noncurrent liabilities” of $6.1 million and $2.9 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, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions The affiliate transactions reflected in the consolidated statements of comprehensive income (loss) include transactions between the Company and Hiland Partners, LP and its subsidiaries ("Hiland"). Hiland was controlled by the Company's principal shareholder through February 13, 2015, at which time it was sold to an unaffiliated third party. As a result of the sale, the prior related party relationship between the Company and Hiland terminated as of February 13, 2015, which resulted in a reduction in certain affiliate transactions recognized in the Company's financial statements at December 31, 2015 and for the year then ended. The Company historically sold a portion of its natural gas production to Hiland. For the years ended December 31, 2015 , 2014 , and 2013 , these sales amounted to $1.4 million , $95.1 million , and $100.4 million , respectively, net of transportation and processing costs, and are included in the caption “Crude oil and natural gas sales to affiliates” in the consolidated statements of comprehensive income (loss). At December 31, 2015 nothing was due to the Company and at December 31, 2014 , $13.1 million was due to the Company from Hiland, which is included in the caption “Receivables—Affiliated parties” in the consolidated balance sheets. At December 31, 2015 nothing was due from the Company and at December 31, 2014 , $0.3 million was due from the Company to Hiland for transportation and processing costs associated with the transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. In prior years, the Company engaged in crude oil trades with an affiliate from time to time to obtain space on pipeline systems in the Company's operating areas. There were no crude oil purchases or sales with affiliates in 2015 or 2014. In 2013, the Company purchased 30,000 barrels from an affiliate for $3.0 million and had no crude oil sales to the affiliate. The Company capitalized costs of $2.6 million , $5.9 million and $5.7 million in 2015 , 2014 , and 2013 , respectively, associated with drilling rig services provided by an affiliate. Hiland historically provided field services such as compression, purchases of residue fuel gas and reclaimed crude oil, and reimbursements of generator rentals and fuel. Production and other expenses attributable to these transactions with Hiland were $1.7 million , $5.1 million and $1.4 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. The total amount paid to these affiliates, a portion of which was billed to other interest owners, was $7.7 million , $58.2 million and $48.5 million for the years ended December 31, 2015 , 2014 , and 2013 , respectively. At December 31, 2015 nothing was due to these affiliates and at December 31, 2014 , $5.6 million was due to these affiliates related to the transactions, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets. Certain officers 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 $0.7 million , $1.7 million , and $2.3 million and received payments from these affiliates of $0.5 million , $0.8 million , and $1.3 million during the years ended December 31, 2015 , 2014 , and 2013 , respectively, relating to the operations of the respective properties. At December 31, 2015 and 2014 , $106,000 and $207,000 was due from these affiliates and approximately $52,000 and $133,000 was due to these affiliates, respectively, relating to these transactions. 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 2015 , 2014 , and 2013 , the Company charged affiliates approximately $9,600 , $51,000 , and $55,000 , respectively, for use of its corporate aircraft, crews, fuel, utilities and reimbursement of expenses and received $33,000 , $39,000 , and $379,000 from affiliates in 2015 , 2014 , and 2013 , respectively. The Company was charged $236,000 , $97,000 , and $51,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2015 , 2014 , and 2013 and paid $221,000 , $34,000 , and $238,000 to the affiliates in 2015 , 2014 , and 2013 , respectively. The Company incurred costs for various field projects that have been ongoing with an entity that became an affiliate of the Company in the third quarter of 2014. During the fourth quarter of 2015, the affiliate relationship terminated. The total amount invoiced and capitalized for 2015 and 2014 associated with the projects was $8.8 million and $1.8 million , respectively. The total amount paid, a portion of which was billed to other interest owners, was $9.2 million and $1.9 million for 2015 and 2014 respectively. Nothing was owed by the Company at December 31, 2015 and $1.2 million was owed by the Company at December 31, 2014, which is included in the caption “Payables to affiliated parties” in the consolidated balance sheets.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation	Stock-Based Compensation The Company has granted restricted stock to employees and directors pursuant to the Continental Resources, Inc. 2005 Long-Term Incentive Plan (“2005 Plan”) and 2013 Long-Term Incentive Plan ("2013 Plan") as discussed below. The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $51.8 million , $54.4 million , and $39.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved a maximum of 19,680,072 shares of common stock that may be issued pursuant to the plan. The 2013 Plan replaced the Company's 2005 Plan as the instrument used to grant long-term incentive awards and no further awards will be granted under the 2005 Plan. However, restricted stock awards granted under the 2005 Plan prior to the adoption of the 2013 Plan will remain outstanding in accordance with their terms. As of December 31, 2015 , the Company had a maximum of 17,028,213 shares of restricted stock available to grant to officers, directors and 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, 2005 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, 2012 to December 31, 2015 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2012 3,258,924 $ 31.64 Granted 522,518 48.98 Vested (929,618 ) 23.65 Forfeited (137,512 ) 35.96 Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 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 at the vesting date of restricted stock that vested during 2015 , 2014 and 2013 was $23.6 million , $58.2 million and $49.4 million , respectively. As of December 31, 2015 , there was approximately $67 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 1.2 years.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Loss) (Notes)	12 Months Ended
	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets. The following table summarizes the change in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 : Year ended December 31, In thousands 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (385 ) $ — Foreign currency translation adjustments (2,969 ) (385 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss.

Property Dispositions

Property Dispositions	12 Months Ended
	Dec. 31, 2015
Extractive Industries [Abstract]
Property Acquisitions and Dispositions	Property Dispositions During the year ended December 31, 2015 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $34.0 million . The proceeds primarily related to the assignment of certain non-producing leasehold acreage in Oklahoma to a third party for $25.9 million in May 2015. The Company recognized a pre-tax gain on the transaction of $20.5 million . The assigned properties represented an immaterial portion of the Company’s leasehold acreage. During the year ended December 31, 2014 , the Company sold certain non-strategic properties in various areas to third parties for proceeds totaling $129.4 million . The proceeds primarily related to dispositions of properties in the Niobrara play in Colorado and Wyoming in March 2014 for proceeds totaling $30.3 million and $85.8 million of proceeds received in conjunction with the disposition of a portion of the Company's Northwest Cana properties in Oklahoma in September 2014. The disposed properties represented an immaterial portion of the Company’s total proved reserves, production, and revenues.

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude Oil and Natural Gas Property Information	Crude Oil and Natural Gas Property Information The tables reflected below represent consolidated figures for the Company and its subsidiaries. In 2014, the Company initiated exploratory drilling activities in Canada. Through December 31, 2015, those drilling activities have not had a material impact on the Company's total capital expenditures, production, and revenues. Accordingly, the results of operations, costs incurred, and capitalized costs associated with the Canadian operations have not been shown separately from the consolidated figures in the tables below. The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands 2015 2014 2013 Crude oil and natural gas sales $ 2,552,531 $ 4,203,022 $ 3,573,431 Production expenses (348,897 ) (352,472 ) (282,197 ) Production taxes and other expenses (200,637 ) (349,760 ) (298,787 ) Exploration expenses (19,413 ) (50,067 ) (34,947 ) Depreciation, depletion, amortization and accretion (1,722,336 ) (1,338,351 ) (953,796 ) Property impairments (402,131 ) (616,888 ) (220,508 ) Income tax benefit (provision) 33,680 (559,311 ) (659,783 ) Results from crude oil and natural gas producing activities $ (107,203 ) $ 936,173 $ 1,123,413 Costs incurred in crude oil and natural gas activities Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2015 , 2014 and 2013 are presented below: Year ended December 31, In thousands 2015 2014 2013 Property acquisition costs: Proved $ 557 $ 48,917 $ 16,604 Unproved 168,492 409,529 546,881 Total property acquisition costs 169,049 458,446 563,485 Exploration Costs 241,523 863,606 687,767 Development Costs 2,148,530 3,670,448 2,549,203 Total $ 2,559,102 $ 4,992,500 $ 3,800,455 Exploration costs above include asset retirement costs of $3.3 million , $1.2 million and $1.8 million and development costs above include asset retirement costs of $19.5 million , $19.1 million and $6.0 million for the years ended December 31, 2015 , 2014 and 2013 , respectively. Aggregate capitalized costs Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2015 and 2014 are as follows: December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Total 20,203,712 18,012,047 Less accumulated depreciation, depletion and amortization (6,374,218 ) (4,601,864 ) Net capitalized costs $ 13,829,494 $ 13,410,183 Under the successful efforts method of accounting, the costs of drilling an exploratory well are capitalized pending determination of whether proved reserves can be attributed to the discovery. When initial drilling operations are complete, management attempts to determine whether the well has discovered crude oil and natural gas reserves and, if so, whether those reserves can be classified as proved reserves. Often, the determination of whether proved reserves can be recorded under SEC guidelines cannot be made when drilling is completed. In those situations where management believes that economically producible hydrocarbons have not been discovered, the exploratory drilling costs are reflected on the consolidated statements of comprehensive income (loss) 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 2015 2014 2013 Balance at January 1 $ 93,421 $ 152,775 $ 92,699 Additions to capitalized exploratory well costs pending determination of proved reserves 132,806 627,853 548,933 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (160,779 ) (671,618 ) (479,507 ) Capitalized exploratory well costs charged to expense (6,051 ) (15,589 ) (9,350 ) Balance at December 31 $ 59,397 $ 93,421 $ 152,775 Number of gross wells 73 119 67 As of December 31, 2015 , exploratory drilling costs of $1.7 million , representing three non-operated wells, were suspended one year beyond the completion of drilling. Evaluation of these non-operated wells is not within the Company's control and a final determination by the operator may not occur until 2017. Of the suspended costs, $0.1 million was incurred in 2014 and $1.6 million was incurred in 2013 .

Supplemental Crude Oil and Natu

Supplemental Crude Oil and Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2015
Supplemental Crude Oil and Natural Gas Information [Abstract]
Supplemental Crude Oil and Natural Gas Information (Unaudited)	Supplemental Crude Oil and Natural Gas Information (Unaudited) The table below shows estimates of proved reserves prepared by the Company’s internal technical staff and independent external reserve engineers in accordance with SEC definitions. Ryder Scott Company, L.P. ("Ryder Scott") prepared reserve estimates for properties comprising approximately 99% , 99% , and 99% of the Company’s discounted future net cash flows (PV-10) as of December 31, 2015 , 2014 , and 2013 , respectively. Properties comprising 99% of proved crude oil reserves and 97% of proved natural gas reserves were evaluated by Ryder Scott as of December 31, 2015 . Remaining reserve estimates were prepared by the Company’s internal technical staff. All proved reserves stated herein are located in the United States. No proved reserves have been recorded for the Company's Canadian operations at December 31, 2015 . 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, 2015 , 2014 and 2013 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, 2015 , 2014 and 2013 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 Proved reserves as of December 31, 2012 561,163 1,341,084 784,677 Revisions of previous estimates (55,783 ) (241,623 ) (96,054 ) Extensions, discoveries and other additions 267,009 1,065,870 444,654 Production (34,989 ) (87,730 ) (49,610 ) Sales of minerals in place — — — Purchases of minerals in place 388 419 458 Proved reserves as of December 31, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811 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. Downward revisions to proved reserves in 2013 primarily represented the removal of PUD reserves resulting from a decision in 2013 to focus the Company's drilling program on certain areas of the Bakken and SCOOP plays with more attractive rates of return and multi-well pad drilling capabilities, while building on success in the Company's development of the Lower Three Forks reservoirs in the Bakken. Downward revisions to proved reserves in 2014 resulted from the Company refining its drilling program and reducing its planned rig count in response to the significant decrease in crude oil prices in the latter part of 2014, which contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. Downward revisions to proved reserves in 2015 resulted primarily from the significant decrease in commodity prices in 2015. The 12-month average price for crude oil decreased 47% from $94.99 per Bbl for 2014 to $50.28 per Bbl for 2015, while the 12-month average price for natural gas decreased 41% from $4.35 per MMBtu for 2014 to $2.58 per MMBtu for 2015. These decreases shortened the economic lives of certain producing properties and caused certain exploration and development projects to become uneconomic which had an adverse impact on the Company's proved reserve estimates, resulting in downward revisions of 185 MMBo and 391 Bcf (totaling 251 MMBoe) in 2015. In response to the continued decrease in commodity prices throughout 2015, the Company has further refined its drilling program and reduced its planned rig count to concentrate its efforts in core areas of North Dakota and Oklahoma that provide the best opportunities to improve recoveries and rates of return. The refinement of the Company's drilling program contributed to the removal of PUD reserves no longer scheduled to be developed within five years from the date in which they were first booked. One element leading to the removal is an increased emphasis on multi-well pad drilling in the Bakken, which resulted in the removal of PUDs in certain areas in favor of PUDs more likely to be developed with pad drilling where operating efficiencies may be realized. Further, in the SCOOP play the Company removed certain PUD locations originally planned to be developed with standard lateral drilling lengths in favor of PUDs to be developed with extended length laterals in similar locations that provide opportunities for improved well productivity and economics. The combination of these and other factors resulted in the removal of 65 MMBo and 197 Bcf (totaling 98 MMBoe) of PUD reserves in 2015. Additionally, changes in anticipated production performance on certain properties resulted in 63 MMBo of downward revisions to crude oil proved reserves and 125 Bcf of upward revisions to natural gas proved reserves (netting to 42 MMBoe of downward revisions) in 2015. The downward revisions described above were partially offset by upward revisions in 2015 due to lower operating costs being realized in conjunction with depressed commodity prices and improvements in operating efficiencies as well as other factors. Extensions, discoveries and other additions . These are additions to proved reserves resulting from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields. Extensions, discoveries and other additions for each of the three years reflected in the table above were primarily due to increases in proved reserves associated with our successful drilling activity in our Bakken and SCOOP plays. Proved reserve additions in the Bakken totaled 75 MMBo and 124 Bcf (totaling 96 MMBoe) and reserve additions in SCOOP totaled 36 MMBo and 340 Bcf (totaling 93 MMBoe) for the year ended December 31, 2015 . Additionally, 2015 extensions and discoveries were significantly impacted by successful drilling results in the Northwest Cana/STACK area, resulting in proved reserve additions of 20 MMBo and 222 Bcf (totaling 57 MMBoe) in 2015 . Sales of minerals in place. These are reductions to proved reserves resulting from the disposition of properties during a period. See Note 14. Property Dispositions for a discussion of notable dispositions. Purchases of minerals in place. These are additions to proved reserves resulting from the acquisition of properties during a period. There were no notable acquisitions in the three years reflected in the table above. 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, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 Proved Developed Reserves Crude oil (MBbl) 326,798 342,137 278,630 Natural Gas (MMcf) 1,190,343 962,051 768,969 Total (MBoe) 525,188 502,479 406,792 Proved Undeveloped Reserves Crude oil (MBbl) 373,716 524,223 459,158 Natural Gas (MMcf) 1,961,443 1,946,335 1,309,051 Total (MBoe) 700,623 848,612 677,333 Total Proved Reserves Crude oil (MBbl) 700,514 866,360 737,788 Natural Gas (MMcf) 3,151,786 2,908,386 2,078,020 Total (MBoe) 1,225,811 1,351,091 1,084,125 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 relatively major 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, 2015 , 2014 and 2013 . December 31, In thousands 2015 2014 2013 Future cash inflows $ 36,551,672 $ 90,867,459 $ 78,646,274 Future production costs (10,869,493 ) (25,799,221 ) (21,333,460 ) Future development and abandonment costs (6,935,958 ) (12,842,174 ) (10,250,789 ) Future income taxes (3,717,612 ) (13,800,737 ) (12,447,127 ) Future net cash flows 15,028,609 38,425,327 34,614,898 10% annual discount for estimated timing of cash flows (8,552,325 ) (19,992,293 ) (18,319,131 ) Standardized measure of discounted future net cash flows $ 6,476,284 $ 18,433,034 $ 16,295,767 The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $41.63 , $84.54 , and $91.50 per barrel at December 31, 2015 , 2014 and 2013 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $2.35 , $6.06 , and $5.36 per Mcf at December 31, 2015 , 2014 and 2013 , 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 2015 2014 2013 Standardized measure of discounted future net cash flows at January 1 $ 18,433,034 $ 16,295,767 $ 11,180,357 Extensions, discoveries and improved recoveries, less related costs 1,091,283 5,516,528 6,613,665 Revisions of previous quantity estimates (2,156,028 ) (1,755,366 ) (1,765,300 ) Changes in estimated future development and abandonment costs 5,008,731 476,665 1,942,585 Purchases (sales) of minerals in place, net (7,768 ) (3,196 ) 12,012 Net change in prices and production costs (16,111,142 ) (1,925,349 ) 263,541 Accretion of discount 1,843,303 1,629,576 1,118,036 Sales of crude oil and natural gas produced, net of production costs (2,002,997 ) (3,500,790 ) (2,992,447 ) Development costs incurred during the period 1,394,584 2,466,748 1,210,223 Change in timing of estimated future production and other (3,844,259 ) (309,902 ) 464,111 Change in income taxes 2,827,543 (457,647 ) (1,751,016 ) Net change (11,956,750 ) 2,137,267 5,115,410 Standardized measure of discounted future net cash flows at December 31 $ 6,476,284 $ 18,433,034 $ 16,295,767

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on derivative instruments, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) 2014 (3) (4) Total revenues (1) $ 972,495 $ 886,095 $ 1,645,328 $ 1,297,700 Gain (loss) on derivative instruments, net (1) $ (39,674 ) $ (262,524 ) $ 473,999 $ 387,958 Property impairments (2) $ 58,208 $ 79,316 $ 85,561 $ 393,803 Income from operations $ 421,317 $ 236,394 $ 944,897 $ 265,228 Net income $ 226,234 $ 103,538 $ 533,521 $ 114,048 Net income per share: Basic $ 0.61 $ 0.28 $ 1.45 $ 0.31 Diluted $ 0.61 $ 0.28 $ 1.44 $ 0.31 (1) Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) The 2014 third quarter includes a $24.5 million pre-tax ( $15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt . (4) Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ( $273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities.

Organization and Summary of S24

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
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 primarily located 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 all properties south of Kansas and west of the Mississippi River including various plays in the SCOOP (South Central Oklahoma Oil Province), STACK (Sooner Trend Anadarko Canadian Kingfisher), Northwest Cana and Arkoma Woodford areas of Oklahoma. The East region is comprised of undeveloped leasehold acreage east of the Mississippi River with no current drilling or production operations. A substantial portion of the Company’s operations are concentrated in the North region, with that region comprising approximately 68% of the Company’s crude oil and natural gas production and approximately 77% of its crude oil and natural gas revenues for the year ended December 31, 2015 . The Company's principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. As of December 31, 2015 , approximately 58% of the Company’s estimated proved reserves were located in the North region. In recent years, the Company has significantly expanded its activity in the South region with its discovery of the SCOOP play and its increased activity in the Northwest Cana and STACK plays. The South region comprised approximately 32% of the Company's crude oil and natural gas production, 23% of its crude oil and natural gas revenues, and 42% of its estimated proved reserves at December 31, 2015 . The Company has focused its operations on the exploration and development of crude oil since the 1980s. For the year ended December 31, 2015 , crude oil accounted for approximately 66% of the Company’s total production and approximately 85% of its crude oil and natural gas revenues. Crude oil represents approximately 57% of the Company's estimated proved reserves as of December 31, 2015 .
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.
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, 2015 and 2014 were not material.
Cash and Cash Equivalents	Cash and cash equivalents The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents. The Company maintains its cash and cash equivalents in accounts that may not be federally insured. As of December 31, 2015 , the Company had cash deposits in excess of federally insured amounts of approximately $10.7 million . The Company has not experienced any losses in such accounts and believes it is not exposed to significant credit risk in this area.
Accounts Receivable	Accounts receivable The Company operates exclusively in crude oil and natural gas exploration and production related activities. Receivables arising from crude oil and natural gas sales and joint interest receivables are generally unsecured. Accounts receivable are due within 30 days and are considered delinquent after 60 days. The Company determines its allowance for doubtful accounts by considering a number of factors, including the length of time accounts are past due, the Company’s history of losses, and the customer or working interest owner’s ability to pay. The Company writes off specific receivables when they become noncollectable and any payments subsequently received on those receivables are credited to the allowance for doubtful accounts. Write-offs of noncollectable receivables have historically not been material.
Concentration of Credit Risk	Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with several significant purchasers. For the year ended December 31, 2015 , sales to the Company’s largest purchaser accounted for approximately 11% of its total crude oil and natural gas sales. No other purchasers accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2015 . 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 various regions.
Inventories	Inventories Inventory is comprised of crude oil held in storage or as line fill in pipelines and tubular goods and equipment to be used in the Company's exploration and development activities. Crude oil inventories are valued at the lower of cost or market primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued at the lower of cost or market, with cost determined primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179
Crude Oil and Natural Gas Properties	Crude oil and natural gas properties The Company uses the successful efforts method of accounting for crude oil and natural gas properties whereby costs incurred to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves, to drill and equip development wells, and expenditures for enhanced recovery operations are capitalized. Geological and geophysical costs, seismic costs incurred for exploratory projects, lease rentals and costs associated with unsuccessful exploratory wells or projects are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. To the extent a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between capitalized development costs and exploration expense. Maintenance, repairs and costs of injection are expensed as incurred, except that the costs of replacements or renewals that expand capacity or improve production are capitalized. Under the successful efforts method of accounting, the Company capitalizes exploratory drilling costs on the balance sheet pending determination of whether the well has found proved reserves in economically producible quantities. The Company capitalizes costs associated with the acquisition or construction of support equipment and facilities with the drilling and development costs to which they relate. If proved reserves are found by an exploratory well, the associated capitalized costs become part of well equipment and facilities. However, if proved reserves are not found, the capitalized costs associated with the well are expensed, net of any salvage value. Production expenses are those costs incurred by the Company to operate and maintain its crude oil and natural gas properties and associated equipment and facilities. Production expenses include labor costs to operate the Company’s properties, repairs and maintenance, waste water disposal costs, and materials and supplies utilized in the Company’s operations.
Service Property and Equipment	Service property and equipment Service property and equipment consist primarily of automobiles and aircraft; machinery and equipment; gathering systems; storage tanks; office and computer equipment, software, furniture and fixtures; 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 Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40
Depreciation, Depletion and Amortization	Depreciation, depletion and amortization Depreciation, depletion and amortization of capitalized drilling and development costs of producing crude oil and natural gas properties, including related support equipment and facilities, are computed using the unit-of-production method on a field basis based on total estimated proved developed reserves. Amortization of producing leaseholds is based on the unit-of-production method using total estimated proved reserves. In arriving at rates under the unit-of-production method, the quantities of recoverable crude oil and natural gas reserves are established based on estimates made by the Company’s internal geologists and engineers and external independent reserve engineers. Upon sale or retirement of properties, the cost and related accumulated depreciation, depletion and amortization are eliminated from the accounts and the resulting gain or loss, if any, is recognized. Unit of production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset Retirement Obligations	Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
Asset Impairment	Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. Non-producing crude oil and natural gas properties primarily consist of undeveloped leasehold costs and costs associated with the purchase of certain proved undeveloped reserves. Impairment losses for non-producing properties 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 drilling plans, 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 three-year term loan, note payable, and revolving credit facility and any amendments thereto are capitalized and amortized over the terms of the arrangements on a straight-line basis, the use of which approximates the effective interest method. Costs incurred upon the issuances of the Company's various senior notes (collectively, the “Notes”) were capitalized and are being amortized over the terms of the Notes using the effective interest method.
Derivative Instruments	Derivative instruments The Company recognizes its derivative instruments on the balance sheet as either assets or liabilities measured at fair value with such amounts classified as current or long-term based on contractual settlement dates. The accounting for the changes in fair value of a derivative depends on the intended use of the derivative and resulting designation. The Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marks its derivative instruments to fair value and recognizes the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Gain (loss) on derivative instruments, net.”
Fair Value of Financial Instruments	Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company's financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2015 and 2014 .
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. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. 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.
Earnings Per Share	arnings per share Basic net income (loss) per share is computed by dividing net income (loss) by the weighted-average number of shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution of non-vested restricted stock awards, which are calculated using the treasury stock method.
Foreign Currency Transactions and Translations Policy	oreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a 100%-owned Canadian subsidiary. The Company has designated the Canadian dollar as the functional currency for its Canadian operations. Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in "Accumulated other comprehensive loss" within shareholders’ equity on the consolidated balance sheets.
New Accounting Pronouncements	ew accounting pronouncements In April 2015, the Financial Accounting Standards Board issued Accounting Standards Update ("ASU") 2015-03, Interest—Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs ("ASU 2015-03"). The new standard requires debt issuance costs related to a recognized term debt liability, such as the Company's senior notes, three-year term loan and note payable, be presented in the balance sheet as a direct deduction from the carrying amount of that term debt liability, consistent with the presentation of a debt discount. Under previous guidance, debt issuance costs were required to be presented in the balance sheet as an asset. The new standard does not affect the existing recognition and measurement guidance for debt issuance costs. The new standard is effective for annual and interim periods beginning after December 15, 2015, with early adoption permitted. The Company early adopted ASU 2015-03 as of June 30, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified unamortized debt issuance costs associated with its senior notes and note payable, which totaled $65.7 million and $69.0 million as of June 30, 2015 and December 31, 2014, respectively, from "Other noncurrent assets" to a reduction of "Long-term debt, net of current portion" on the consolidated balance sheets. Unamortized debt issuance costs reflected as a reduction of long-term debt subsequently totaled $64.0 million as of December 31, 2015 , inclusive of costs incurred upon execution of the Company's new term loan in November 2015 as discussed in Note 7. Long-Term Debt . Adoption of ASU 2015-03 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The December 31, 2014 carrying amounts for the Company's senior notes and note payable presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-03. Unamortized debt issuance costs associated with the Company's revolving credit facility, which amounted to $7.8 million and $7.0 million as of December 31, 2015 and 2014, respectively, were not reclassified and remain reflected in "Other noncurrent assets" on the consolidated balance sheets. In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes , which requires entities with a classified balance sheet to present all deferred tax assets and deferred tax liabilities as noncurrent instead of separating deferred taxes into current and noncurrent amounts. The standard will be effective for public companies for annual and interim periods beginning after December 15, 2016, with early adoption permitted. The Company early adopted ASU 2015-17 as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. As a result of the adoption, the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. Adoption of ASU 2015-17 had no impact on the Company's current and previously reported shareholders' equity, results of operations, or cash flows. The affected prior period deferred income tax account balances presented throughout this report on Form 10-K have been adjusted to reflect the retroactive adoption of ASU 2015-17.

Organization and Summary of S25

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2015 and 2014 consisted of the following: December 31, In thousands 2015 2014 Tubular goods and equipment $ 15,633 $ 15,659 Crude oil 78,518 86,520 Total $ 94,151 $ 102,179
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 Automobiles and aircraft 5-10 Machinery and equipment 6-10 Gathering systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-10 Enterprise resource planning software 25 Buildings and improvements 10-40
Summary of Changes in Future Abandonment Liabilities	The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2013 through December 31, 2015 : In thousands 2015 2014 2013 Asset retirement obligations at January 1 $ 76,708 $ 55,787 $ 47,171 Accretion expense 4,740 3,366 2,767 Revisions (1) 15,068 9,916 2,826 Plus: Additions for new assets 7,404 9,022 6,009 Less: Plugging costs and sold assets (1,011 ) (1,383 ) (2,986 ) Total asset retirement obligations at December 31 $ 102,909 $ 76,708 $ 55,787 Less: Current portion of asset retirement obligations at December 31 (2) 1,658 1,246 1,434 Non-current portion of asset retirement obligations at December 31 $ 101,251 $ 75,462 $ 54,353 (1) Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties. (2) Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.
Calculation of Basic and Diluted Weighted Average Shares and Net Income per Share	he following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands, except per share data 2015 2014 2013 Income (loss) (numerator): Net income (loss) - basic and diluted $ (353,668 ) $ 977,341 $ 764,219 Weighted average shares (denominator): Weighted average shares - basic 369,540 368,829 368,150 Non-vested restricted stock (1) — 1,929 1,548 Weighted average shares - diluted 369,540 370,758 369,698 Net income (loss) per share: Basic $ (0.96 ) $ 2.65 $ 2.08 Diluted $ (0.96 ) $ 2.64 $ 2.07 (1) During the year ended December 31, 2015 , the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations.

Supplemental Cash Flow Inform26

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
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 tax payments and refunds. 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 2015 2014 2013 Supplemental cash flow information: Cash paid for interest $ 301,743 $ 267,384 $ 209,815 Cash paid for income taxes 30 53,457 29,017 Cash received for income tax refunds 61,403 7 174 Non-cash investing activities: Increase (decrease) in accrued capital expenditures (519,949 ) 290,782 89,482 Asset retirement obligation additions and revisions, net 22,472 18,938 8,835

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Service properties, equipment and other 307,059 274,584 Total property and equipment 20,510,771 18,286,631 Accumulated depreciation, depletion and amortization (6,447,443 ) (4,650,779 ) Net property and equipment $ 14,063,328 $ 13,635,852

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2015
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2015 and 2014 : December 31, In thousands 2015 2014 Prepaid advances from joint interest owners $ 49,917 $ 115,687 Accrued compensation 40,060 39,848 Accrued production taxes, ad valorem taxes and other non-income taxes 21,678 36,550 Accrued interest 62,058 60,861 Current portion of asset retirement obligations 1,658 1,246 Other 1,576 4,965 Accrued liabilities and other $ 176,947 $ 259,157

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas	Natural Gas - Henry Hub Swaps Weighted Average Price Floors Ceilings Weighted Average Price Weighted Average Price Period and Type of Contract MMBtus Range Range January 2016 - December 2016 Swaps - Henry Hub 133,710,000 $ 3.17 January 2017 - December 2017 Swaps - Henry Hub 25,550,000 $ 3.35 Collars - Henry Hub 65,700,000 $2.40 - $3.00 $ 2.47 $2.92 - $3.88 $ 3.08
Realized and Unrealized Gains and Losses on Derivative Instruments	The following table presents cash settlements on matured or liquidated derivative instruments and non-cash gains and losses on open derivative instruments for the periods presented. Cash receipts and payments below reflect proceeds received upon early liquidation of derivative positions and gains or losses on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured or were liquidated during the period. Year ended December 31, In thousands 2015 2014 2013 Cash received (paid) on derivatives: Crude oil fixed price swaps (1) $ — $ 331,591 $ (54,289 ) Crude oil collars (1) — 65,310 (16,867 ) Natural gas fixed price swaps 39,670 (11,551 ) 9,601 Natural gas collars 29,883 — — Cash received (paid) on derivatives, net 69,553 385,350 (61,555 ) Non-cash gain (loss) on derivatives: Crude oil fixed price swaps — 84,792 (117,580 ) Crude oil collars — 1,121 (8,587 ) Crude oil written call options 4,715 3,981 — Natural gas fixed price swaps 41,828 62,699 (4,029 ) Natural gas collars (25,011 ) 21,816 — Non-cash gain (loss) on derivatives, net 21,532 174,409 (130,196 ) Gain (loss) on derivative instruments, net $ 91,085 $ 559,759 $ (191,751 ) (1) Net cash receipts for crude oil swaps and collars for the year ended December 31, 2014 include $433 million of proceeds received from crude oil derivative contracts that were settled in the fourth quarter of 2014 prior to their contractual maturities. Of the proceeds, $373 million related to crude oil swap liquidations and $60 million related to crude oil collar liquidations.
Balance sheet offsetting of derivative assets and liabilities	The following table present the gross amounts of recognized derivative assets and liabilities, the amounts offset under netting arrangements with counterparties, and the resulting net amounts presented in the consolidated balance sheets for the periods presented, all at fair value. December 31, In thousands 2015 2014 Commodity derivative assets: Gross amounts of recognized assets $ 120,385 $ 84,431 Gross amounts offset on balance sheet (11,903 ) (16 ) Net amounts of assets on balance sheet 108,482 84,415 Commodity derivative liabilities: Gross amounts of recognized liabilities (19,192 ) (4,770 ) Gross amounts offset on balance sheet 11,903 16 Net amounts of liabilities on balance sheet $ (7,289 ) $ (4,754 )
Schedule Of Derivative Assets Liabilities At Fair Value Net By Balance Sheet Classification Table	The following table reconciles the net amounts disclosed above to the individual financial statement line items in the consolidated balance sheets. December 31, In thousands 2015 2014 Derivative assets $ 93,922 $ 52,423 Noncurrent derivative assets 14,560 31,992 Net amounts of assets on balance sheet 108,482 84,415 Derivative liabilities (3,583 ) (1,645 ) Noncurrent derivative liabilities (3,706 ) (3,109 ) Net amounts of liabilities on balance sheet (7,289 ) (4,754 ) Total derivative assets, net $ 101,193 $ 79,661
ICE Brent [Member]
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Crude Oil	At December 31, 2015 , the Company had outstanding derivative contracts with respect to future production as set forth in the tables below. The hedged volumes reflected below represent an aggregation of multiple derivative contracts that have varying durations and may not be realized on a ratable basis over a calendar year. Crude Oil - ICE Brent Period and Type of Contract Bbls Ceiling Price January 2016 - December 2016 Written call options - ICE Brent (1) 1,464,000 $ 107.70 (1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 . Fair value measurements at December 31, 2015 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 104,426 $ — $ 104,426 Collars — (3,195 ) — (3,195 ) Written call options — (38 ) — (38 ) Total $ — $ 101,193 $ — $ 101,193 Fair value measurements at December 31, 2014 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets (liabilities): Fixed price swaps $ — $ 62,599 $ — $ 62,599 Collars — 21,816 — 21,816 Written call options — (4,754 ) $ — (4,754 ) Total $ — $ 79,661 $ — $ 79,661
Unobservable inputs used in level 3 fair value measurements	Unobservable Input Assumption Future production Future production estimates for each property Forward commodity prices Forward NYMEX swap prices through 2020 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of field Ranging from 0 to 34 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2015 2014 2013 Proved property impairments $ 138,878 $ 324,302 $ 51,805 Unproved property impairments 263,253 292,586 168,703 Total $ 402,131 $ 616,888 $ 220,508
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, 2015 December 31, 2014 In thousands Carrying Amount Fair Value Carrying Amount Fair Value Debt: Credit facility $ 853,000 $ 853,000 $ 165,000 $ 165,000 Term loan 498,274 500,000 — — Note payable 14,309 12,500 16,375 14,900 7.375% Senior Notes due 2020 196,574 179,200 195,997 213,000 7.125% Senior Notes due 2021 395,365 388,300 394,668 421,000 5% Senior Notes due 2022 1,996,831 1,480,400 1,996,507 1,857,900 4.5% Senior Notes due 2023 1,482,451 1,061,000 1,480,479 1,372,800 3.8% Senior Notes due 2024 989,932 700,300 988,940 868,700 4.9% Senior Notes due 2044 691,052 430,500 690,912 572,400 Total debt $ 7,117,788 $ 5,605,200 $ 5,928,878 $ 5,485,700

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $49.6 million and $52.6 million at December 31, 2015 and 2014 , respectively, consists of the following. See Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements for a discussion of the impact on long-term debt from the Company's adoption of ASU 2015-03. December 31, In thousands 2015 2014 Credit facility $ 853,000 $ 165,000 Term loan 498,274 — Note payable 14,309 16,375 7.375% Senior Notes due 2020 196,574 195,997 7.125% Senior Notes due 2021 395,365 394,668 5% Senior Notes due 2022 1,996,831 1,996,507 4.5% Senior Notes due 2023 1,482,451 1,480,479 3.8% Senior Notes due 2024 989,932 988,940 4.9% Senior Notes due 2044 691,052 690,912 Total debt 7,117,788 5,928,878 Less: Current portion of long-term debt 2,144 2,078 Long-term debt, net of current portion $ 7,115,644 $ 5,926,800
Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods of Outstanding Senior Note Obligations	The following table summarizes the face values, maturity dates, semi-annual interest payment dates, and optional redemption periods related to the Company’s outstanding senior note obligations at December 31, 2015 . 2020 Notes 2021 Notes 2022 Notes 2023 Notes 2024 Notes 2044 Notes Face value (in thousands) $200,000 $400,000 $2,000,000 $1,500,000 $1,000,000 $700,000 Maturity date Oct 1, 2020 April 1, 2021 Sep 15, 2022 April 15, 2023 June 1, 2024 June 1, 2044 Interest payment dates April 1, Oct 1 April 1, Oct 1 March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 June 1, Dec 1 Call premium redemption period (1) Oct 1, 2015 April 1, 2016 March 15, 2017 — — — Make-whole redemption period (2) Oct 1, 2015 April 1, 2016 March 15, 2017 Jan 15, 2023 Mar 1, 2024 Dec 1, 2043 (1) On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series 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 of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The items comprising the provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2015 2014 2013 Current income tax provision: United States federal $ — $ — $ 6,193 Various states 24 20 16 Total current income tax provision 24 20 6,209 Deferred income tax provision (benefit): United States federal (140,578 ) 527,315 403,002 Various states (40,863 ) 57,362 39,619 Total deferred income tax provision (benefit) (181,441 ) 584,677 442,621 Total provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, In thousands 2015 2014 2013 Expected income tax expense (benefit) based on US statutory tax rate of 35% $ (187,280 ) $ 546,713 $ 424,567 State income taxes, net of federal benefit (16,219 ) 42,169 25,838 Canadian valuation allowance 13,503 4,389 — Effect of differing statutory tax rate in Canada 5,239 (1,900 ) — Other, net 3,340 (6,674 ) (1,575 ) Provision (benefit) for income taxes $ (181,417 ) $ 584,697 $ 448,830
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2015 and 2014 are reflected in the table below. As discussed in Note 1. Organization and Summary of Significant Accounting Policies—New accounting pronouncements , in November 2015 the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes . This new standard requires that all deferred tax assets and deferred tax liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The new standard was early-adopted by the Company as of December 31, 2015 on a retrospective basis to all prior balance sheet periods presented. Accordingly, all deferred tax assets and deferred tax liabilities have been reflected as noncurrent and the Company reclassified $36.2 million and $145.3 million as of December 31, 2015 and 2014, respectively, from "Accrued liabilities and other" to “Deferred income tax liabilities, net” on the consolidated balance sheets. December 31, In thousands 2015 2014 Deferred tax assets United States net operating loss carryforwards 398,024 60,904 Canadian net operating loss carryforwards 17,892 4,899 Alternative minimum tax carryforwards 40,796 38,715 Equity compensation 32,910 22,255 Other 11,048 8,920 Total deferred tax assets 500,670 135,693 Canadian valuation allowance (17,892 ) (4,389 ) Total deferred tax assets, net of valuation allowance 482,778 131,304 Deferred tax liabilities Property and equipment (2,528,125 ) (2,254,343 ) Non-cash gains on derivatives (38,452 ) (30,269 ) Gain on derivative liquidation (4,158 ) (132,356 ) Other (2,271 ) (1,132 ) Total deferred tax liabilities (2,573,006 ) (2,418,100 ) Deferred income tax liabilities, net $ (2,090,228 ) $ (2,286,796 )

Lease Commitments (Tables)

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Schedule of Minimum Future Rental Commitments Under Operating Leases	At December 31, 2015 , the minimum future rental commitments under operating leases having lease terms in excess of one year are as follows: In thousands Total amount 2016 $ 3,348 2017 1,327 2018 979 2019 291 2020 210 Thereafter 3,105 Total obligations $ 9,260

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2015
Stock-Based Compensation Expense	The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income (loss), was $51.8 million , $54.4 million , and $39.9 million for the years ended December 31, 2015 , 2014 and 2013 , respectively.
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, 2012 to December 31, 2015 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2012 3,258,924 $ 31.64 Granted 522,518 48.98 Vested (929,618 ) 23.65 Forfeited (137,512 ) 35.96 Non-vested restricted shares at December 31, 2013 2,714,312 $ 37.50 Granted 1,424,764 61.11 Vested (1,007,166 ) 35.91 Forfeited (453,146 ) 44.90 Non-vested restricted shares at December 31, 2014 2,678,764 $ 49.40 Granted 1,462,534 46.65 Vested (555,517 ) 48.07 Forfeited (336,170 ) 51.23 Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20

Accumulated Other Comprehensi35

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss) [Table Text Block]	The following table summarizes the change in accumulated other comprehensive loss for the years ended December 31, 2015 and 2014 : Year ended December 31, In thousands 2015 2014 Beginning accumulated other comprehensive loss, net of tax $ (385 ) $ — Foreign currency translation adjustments (2,969 ) (385 ) Income tax benefit (1) — — Other comprehensive loss, net of tax (2,969 ) (385 ) Ending accumulated other comprehensive loss, net of tax $ (3,354 ) $ (385 ) (1) A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss.

Crude Oil and Natural Gas Pro36

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2015
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities	The following table sets forth the Company’s consolidated results of operations from crude oil and natural gas producing activities for the years ended December 31, 2015 , 2014 and 2013 . Year ended December 31, In thousands 2015 2014 2013 Crude oil and natural gas sales $ 2,552,531 $ 4,203,022 $ 3,573,431 Production expenses (348,897 ) (352,472 ) (282,197 ) Production taxes and other expenses (200,637 ) (349,760 ) (298,787 ) Exploration expenses (19,413 ) (50,067 ) (34,947 ) Depreciation, depletion, amortization and accretion (1,722,336 ) (1,338,351 ) (953,796 ) Property impairments (402,131 ) (616,888 ) (220,508 ) Income tax benefit (provision) 33,680 (559,311 ) (659,783 ) Results from crude oil and natural gas producing activities $ (107,203 ) $ 936,173 $ 1,123,413
Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities	Costs incurred, both capitalized and expensed, in connection with the Company’s consolidated crude oil and natural gas acquisition, exploration and development activities for the years ended December 31, 2015 , 2014 and 2013 are presented below: Year ended December 31, In thousands 2015 2014 2013 Property acquisition costs: Proved $ 557 $ 48,917 $ 16,604 Unproved 168,492 409,529 546,881 Total property acquisition costs 169,049 458,446 563,485 Exploration Costs 241,523 863,606 687,767 Development Costs 2,148,530 3,670,448 2,549,203 Total $ 2,559,102 $ 4,992,500 $ 3,800,455
Schedule of Aggregate Capitalized Costs Related to Crude Oil and Natural Gas Producing Activities	Aggregate capitalized costs relating to the Company’s consolidated crude oil and natural gas producing activities and related accumulated depreciation, depletion and amortization as of December 31, 2015 and 2014 are as follows: December 31, In thousands 2015 2014 Proved crude oil and natural gas properties $ 19,520,724 $ 17,045,967 Unproved crude oil and natural gas properties 682,988 966,080 Total 20,203,712 18,012,047 Less accumulated depreciation, depletion and amortization (6,374,218 ) (4,601,864 ) Net capitalized costs $ 13,829,494 $ 13,410,183
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 2015 2014 2013 Balance at January 1 $ 93,421 $ 152,775 $ 92,699 Additions to capitalized exploratory well costs pending determination of proved reserves 132,806 627,853 548,933 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (160,779 ) (671,618 ) (479,507 ) Capitalized exploratory well costs charged to expense (6,051 ) (15,589 ) (9,350 ) Balance at December 31 $ 59,397 $ 93,421 $ 152,775 Number of gross wells 73 119 67

Supplemental Crude Oil and Na37

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
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 Proved reserves as of December 31, 2012 561,163 1,341,084 784,677 Revisions of previous estimates (55,783 ) (241,623 ) (96,054 ) Extensions, discoveries and other additions 267,009 1,065,870 444,654 Production (34,989 ) (87,730 ) (49,610 ) Sales of minerals in place — — — Purchases of minerals in place 388 419 458 Proved reserves as of December 31, 2013 737,788 2,078,020 1,084,125 Revisions of previous estimates (67,151 ) (244,783 ) (107,949 ) Extensions, discoveries and other additions 239,526 1,206,569 440,621 Production (44,530 ) (114,295 ) (63,579 ) Sales of minerals in place (123 ) (18,623 ) (3,227 ) Purchases of minerals in place 850 1,498 1,100 Proved reserves as of December 31, 2014 866,360 2,908,386 1,351,091 Revisions of previous estimates (246,840 ) (302,143 ) (297,198 ) Extensions, discoveries and other additions 134,764 710,453 253,173 Production (53,517 ) (164,454 ) (80,926 ) Sales of minerals in place (253 ) (456 ) (329 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2015 700,514 3,151,786 1,225,811
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, 2015 , 2014 and 2013 : December 31, 2015 2014 2013 Proved Developed Reserves Crude oil (MBbl) 326,798 342,137 278,630 Natural Gas (MMcf) 1,190,343 962,051 768,969 Total (MBoe) 525,188 502,479 406,792 Proved Undeveloped Reserves Crude oil (MBbl) 373,716 524,223 459,158 Natural Gas (MMcf) 1,961,443 1,946,335 1,309,051 Total (MBoe) 700,623 848,612 677,333 Total Proved Reserves Crude oil (MBbl) 700,514 866,360 737,788 Natural Gas (MMcf) 3,151,786 2,908,386 2,078,020 Total (MBoe) 1,225,811 1,351,091 1,084,125
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, 2015 , 2014 and 2013 . December 31, In thousands 2015 2014 2013 Future cash inflows $ 36,551,672 $ 90,867,459 $ 78,646,274 Future production costs (10,869,493 ) (25,799,221 ) (21,333,460 ) Future development and abandonment costs (6,935,958 ) (12,842,174 ) (10,250,789 ) Future income taxes (3,717,612 ) (13,800,737 ) (12,447,127 ) Future net cash flows 15,028,609 38,425,327 34,614,898 10% annual discount for estimated timing of cash flows (8,552,325 ) (19,992,293 ) (18,319,131 ) Standardized measure of discounted future net cash flows $ 6,476,284 $ 18,433,034 $ 16,295,767
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 2015 2014 2013 Standardized measure of discounted future net cash flows at January 1 $ 18,433,034 $ 16,295,767 $ 11,180,357 Extensions, discoveries and improved recoveries, less related costs 1,091,283 5,516,528 6,613,665 Revisions of previous quantity estimates (2,156,028 ) (1,755,366 ) (1,765,300 ) Changes in estimated future development and abandonment costs 5,008,731 476,665 1,942,585 Purchases (sales) of minerals in place, net (7,768 ) (3,196 ) 12,012 Net change in prices and production costs (16,111,142 ) (1,925,349 ) 263,541 Accretion of discount 1,843,303 1,629,576 1,118,036 Sales of crude oil and natural gas produced, net of production costs (2,002,997 ) (3,500,790 ) (2,992,447 ) Development costs incurred during the period 1,394,584 2,466,748 1,210,223 Change in timing of estimated future production and other (3,844,259 ) (309,902 ) 464,111 Change in income taxes 2,827,543 (457,647 ) (1,751,016 ) Net change (11,956,750 ) 2,137,267 5,115,410 Standardized measure of discounted future net cash flows at December 31 $ 6,476,284 $ 18,433,034 $ 16,295,767

Quarterly Financial Data (Una38

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2015 and 2014 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2015 Total revenues (1) $ 625,644 $ 796,374 $ 682,669 $ 575,480 Gain (loss) on derivative instruments, net (1) $ 32,755 $ (4,737 ) $ 46,527 $ 16,540 Property impairments (2) $ 147,561 $ 76,872 $ 96,697 $ 81,001 Income (loss) from operations $ (111,276 ) $ 82,447 $ (52,356 ) $ (142,816 ) Net income (loss) $ (131,971 ) $ 403 $ (82,423 ) $ (139,677 ) Net income (loss) per share: Basic $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) Diluted $ (0.36 ) $ — $ (0.22 ) $ (0.38 ) 2014 (3) (4) Total revenues (1) $ 972,495 $ 886,095 $ 1,645,328 $ 1,297,700 Gain (loss) on derivative instruments, net (1) $ (39,674 ) $ (262,524 ) $ 473,999 $ 387,958 Property impairments (2) $ 58,208 $ 79,316 $ 85,561 $ 393,803 Income from operations $ 421,317 $ 236,394 $ 944,897 $ 265,228 Net income $ 226,234 $ 103,538 $ 533,521 $ 114,048 Net income per share: Basic $ 0.61 $ 0.28 $ 1.45 $ 0.31 Diluted $ 0.61 $ 0.28 $ 1.44 $ 0.31 (1) Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods. (3) The 2014 third quarter includes a $24.5 million pre-tax ( $15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt . (4) Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ( $273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities.

Organization and Summary of S39

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Jun. 30, 2015
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 64,000	$ 69,000		$ 65,700
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 13,503	4,389	$ 0
Percentage of operations concentrated in geographically areas	68.00%
Percentage of estimated proved reserves in north region	58.00%
Percentage of crude oil and natural gas production concentrated in south region	32.00%
Percentage of estimated proved reserves in south region	42.00%
Percentage Of Crude Oil And Natural Gas Production Concentrated In Crude Oil	66.00%
Percentage Of Crude Oil and Natural Gas Revenue Concentrated in Crude Oil	85.00%
Cash deposits in excess of federally insured amounts	$ 10,700
Net asset retirement costs	87,500	64,700
Capitalized debt issue costs, relating to long-term debt	71,800	76,100
Accumulated amortization, relating to capitalized debt issue costs	47,000	38,100
Amortization expense related to capitalized debt issuance costs	$ 8,900	9,300	$ 8,600
Percentage Of Estimated Proved Reserves Concentrated In Crude Oil	57.00%
Deferred Tax Liabilities, Net, Current	$ 36,200	145,300
Deferred Tax Assets, Valuation Allowance	(17,892)	(4,389)
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 7,800	$ 7,000
7 3/8% Senior Notes due 2020 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage	7.375%
7 1/8% Senior Notes due 2021 [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Debt instrument interest percentage	7.125%
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	11.00%
North Region [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage Of Revenues Concentrated In Geographically Areas	77.00%
South Region [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage Of Revenues Concentrated In Geographically Areas	23.00%

Organization and Summary of S40

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 15,633	$ 15,659
Crude oil	78,518	86,520
Total	$ 94,151	$ 102,179

Organization and Summary of S41

Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail)	12 Months Ended
	Dec. 31, 2015
Enterprise Resource Planning Software [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Minimum [Member] | Automobiles and Aircraft [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	5 years
Minimum [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	15 years
Minimum [Member] | Storage Tanks [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Minimum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	6 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 and Aircraft [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Maximum [Member] | Gathering Systems [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum [Member] | Storage Tanks [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Maximum [Member] | Machinery and Equipment [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 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 S42

Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 76,708	$ 55,787	$ 47,171
Accretion expense		4,740	3,366	2,767
Revisions	[1]	15,068	9,916	2,826
Plus: Additions for new assets		7,404	9,022	6,009
Less: Plugging costs and sold assets		(1,011)	(1,383)	(2,986)
Total asset retirement obligations at December 31		102,909	76,708	55,787
Less: Current portion of asset retirement obligations at December 31	[2]	1,658	1,246	1,434
Non-current portion of asset retirement obligations at December 31		$ 101,251	$ 75,462	$ 54,353
[1]	Revisions for the years ended December 31, 2015 and 2014 primarily represent an increase in the present value of liabilities from an acceleration in the estimated timing of abandonment prompted by decreases in commodity prices in 2015 and 2014 which shortened the economic lives of certain producing properties.
[2]	Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.

Organization and Summary of S43

Organization and Summary of Significant Accounting Policies - Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended										12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	[1]	Sep. 30, 2014		Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Weighted average number diluted shares excluded from calculation											1,567,000
Income (numerator):
Net income - basic and diluted	$ (139,677)	$ (82,423)	$ 403	$ (131,971)	$ 114,048		$ 533,521		$ 103,538	$ 226,234	$ (353,668)		$ 977,341	$ 764,219
Weighted average shares - basic											369,540,000		368,829,000	368,150,000
Non-vested restricted stock											0	[2]	1,929,000	1,548,000
Weighted average shares - diluted											369,540,000		370,758,000	369,698,000
Net income per share:
Basic (in dollars per share)	$ (0.38)	$ (0.22)	$ 0	$ (0.36)	$ 0.31		$ 1.45	[3]	$ 0.28	$ 0.61	$ (0.96)		$ 2.65	$ 2.08
Diluted (in dollars per share)	$ (0.38)	$ (0.22)	$ 0	$ (0.36)	$ 0.31		$ 1.44	[3]	$ 0.28	$ 0.61	$ (0.96)		$ 2.64	$ 2.07
[1]	Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities.
[2]	1)During the year ended December 31, 2015, the Company had a net loss and therefore the potential dilutive effect of approximately 1,567,000 weighted average restricted shares were not included in the calculation of diluted net loss per share for 2015 because to do so would have been anti-dilutive to the computations.
[3]	The 2014 third quarter includes a $24.5 million pre-tax ($15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt.

Supplemental Cash Flow Inform44

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Supplemental cash flow information:
Cash paid for interest	$ 301,743	$ 267,384	$ 209,815
Cash paid for income taxes	30	53,457	29,017
Cash received for income tax refunds	61,403	7	174
Change in capital expenditures incurred but not paid	(519,949)	290,782	89,482
Non-cash investing activities:
Asset retirement obligation additions and revisions, net	$ 22,472	$ 18,938	$ 8,835

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 19,520,724	$ 17,045,967
Unproved crude oil and natural gas properties	682,988	966,080
Service properties, equipment and other	307,059	274,584
Total property and equipment	20,510,771	18,286,631
Accumulated depreciation, depletion and amortization	(6,447,443)	(4,650,779)
Net property and equipment	$ 14,063,328	$ 13,635,852

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 49,917	$ 115,687
Accrued compensation		40,060	39,848
Accrued production taxes, ad valorem taxes and other non-income taxes		21,678	36,550
Accrued interest		62,058	60,861
Current portion of asset retirement obligations	[1]	1,658	1,246	$ 1,434
Other		1,576	4,965
Accrued liabilities and other		$ 176,947	$ 259,157
[1]	Balance is included in the caption "Accrued liabilities and other" in the consolidated balance sheets.

Derivative Instruments - Summar

Derivative Instruments - Summary of Outstanding Contracts with Respect to Crude Oil (Detail) - ICE Brent [Member] - Call Option January 2016 to December 2016 [Member]	12 Months Ended
	Dec. 31, 2015$ / Barrelsbbl	[1]
Derivative [Line Items]
Volume (Bbls) | bbl	1,464,000
Derivative, Average Price Risk Option Strike Price | $ / Barrels	107.70
[1]	(1) Written call options represent the ceiling positions remaining from the Company's previous crude oil collar contracts. The floor positions of the collars were liquidated in the fourth quarter of 2014. For these written call options, the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price.

Derivative Instruments - Summ48

Derivative Instruments - Summary of Outstanding Contracts with Respect to Natural Gas (Detail) - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2015MMBTU$ / MMBTU$ / bbl
January 2016 to December 2016 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	133,710,000
Swaps Weighted Average Price | $ / MMBTU	3.17
January 2017 to December 2017 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	25,550,000
Swaps Weighted Average Price | $ / MMBTU	3.35
January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Average Cap Price	3.08
Natural Gas Production Derivative Volume, MMBtus | MMBTU	65,700,000
Derivative, Average Floor Price	2.47
Maximum [Member] | January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	3
Derivative, Cap Price	3.88
Minimum [Member] | January 2017 to December 2017 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	2.40
Derivative, Cap Price	2.92

Derivative Instruments - Realiz

Derivative Instruments - Realized and Unrealized Gains and Losses on Derivative Instruments (Detail) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015	[1]	Sep. 30, 2015	[1]	Jun. 30, 2015	[1]	Mar. 31, 2015	[1]	Dec. 31, 2014		Sep. 30, 2014	[1]	Jun. 30, 2014	[1]	Mar. 31, 2014	[1]	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives									$ 433,000									$ 433,000
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	$ 69,553	385,350	$ (61,555)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	21,532	174,409	(130,196)
Gain (loss) on derivative instruments, net	$ 16,540		$ 46,527		$ (4,737)		$ 32,755		$ 387,958	[1],[2]	$ 473,999		$ (262,524)		$ (39,674)		91,085	559,759	(191,751)
Fixed Price Swaps [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives																		373,000
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	0	331,591	(54,289)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	84,792	(117,580)
Fixed Price Swaps [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	39,670	(11,551)	9,601
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	41,828	62,699	(4,029)
Collars [Member] | Crude Oil [Member]
Derivatives, Fair Value [Line Items]
Cash Proceeds from Liquidated Derivatives																		60,000
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	0	65,310	(16,867)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	1,121	(8,587)
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	29,883	0	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(25,011)	21,816	0
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ 4,715	$ 3,981	$ 0
[1]	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
[2]	Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities.

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 120,385	$ 84,431
Commodity derivative assets, Gross amounts offset on balance sheet	(11,903)	(16)
Derivative assets, Net amounts of assets on balance sheet	108,482	84,415
Commodity derivative liability, Gross amounts of recognized liabilities	(19,192)	(4,770)
Commodity derivative liability, Gross amounts offset on balance sheet	11,903	16
Derivative liability, Net amounts of liabilities on balance sheet	$ (7,289)	$ (4,754)

Derivative Instruments Deriva51

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 93,922	$ 52,423
Noncurrent derivative assets	14,560	31,992
Derivative assets, Net amounts of assets on balance sheet	108,482	84,415
Derivative liabilities	(3,583)	(1,645)
Noncurrent derivative liabilities	(3,706)	(3,109)
Derivative liability, Net amounts of liabilities on balance sheet	(7,289)	(4,754)
Total derivative assets, net	$ 101,193	$ 79,661

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 101,193	$ 79,661
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 1 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	101,193	79,661
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	104,426	62,599
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(3,195)	21,816
Fair Value, Inputs, Level 2 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(38)	(4,754)
Fair Value, Inputs, Level 3 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value, Inputs, Level 3 [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	0	0
Fair Value [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	101,193	79,661
Fair Value [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	104,426	62,599
Fair Value [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	(3,195)	21,816
Fair Value [Member] | Call Option [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	$ (38)	$ (4,754)

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 138,878	$ 324,302	$ 51,805
Estimated fair value of proved properties	$ 59,900
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)	34 years
Forward Commodity Prices [Member]
Fair Value Measurements [Line Items]
Forward commodity price escalation assumption used in impairment assessment	3.00%

Fair Value Measurements - Prope

Fair Value Measurements - Property Impairments (Detail) - USD ($) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2015

[1]

Sep. 30, 2015

[1]

Jun. 30, 2015

[1]

Mar. 31, 2015

[1]

Dec. 31, 2014

[1]

Sep. 30, 2014

[1]

Jun. 30, 2014

[1]

Mar. 31, 2014

[1]

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

$ 138,878

$ 324,302

$ 51,805

Unproved property impairments

263,253

292,586

168,703

Total

$ 81,001

$ 96,697

$ 76,872

$ 147,561

$ 393,803

$ 85,561

$ 79,316

$ 58,208

402,131

$ 616,888

$ 220,508

Buffalo Red River Units [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

26,300

Medicine Pole Hill Units [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

32,500

South Region [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

11,400

Non-Bakken North Region [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

8,200

WYOMING

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

17,900

Emerging Areas [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Proved property impairments

$ 42,500

[1]

Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods.

Fair Value Measurements - Fair

Fair Value Measurements - Fair Values of Financial Instruments not Recorded at Fair Value (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,020
Debt instrument, stated interest rate	7.375%
7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,021
Debt instrument, stated interest rate	7.125%
5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,022
Debt instrument, stated interest rate	5.00%
4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,023
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,024
Debt instrument, stated interest rate	3.80%
Senior notes		$ 988,940
4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,044
Debt instrument, stated interest rate	4.90%
Senior notes		690,912
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	$ 853,000	165,000
Term loan		0
Note payable	14,309	16,375
Total debt	7,117,788	5,928,878
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	196,574	195,997
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	395,365	394,668
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,996,831	1,996,507
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,482,451	1,480,479
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	989,932	988,940
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	691,052	690,912
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	853,000	165,000
Term loan	500,000	0
Note payable	12,500	14,900
Total debt	5,605,200	5,485,700
Fair Value [Member] | 7 3/8% Senior Notes due 2020 [Member]
Fair Value Measurements [Line Items]
Senior notes	179,200	213,000
Fair Value [Member] | 7 1/8% Senior Notes due 2021 [Member]
Fair Value Measurements [Line Items]
Senior notes	388,300	421,000
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,480,400	1,857,900
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,061,000	1,372,800
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	700,300	868,700
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 430,500	$ 572,400

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Unamortized Loan Commitment and Origination Fees and Unamortized Discounts or Premiums	$ 49,600	$ 52,600
Less: Current portion of long-term debt	(2,144)	(2,078)
Long-term debt, net of current portion	7,115,644	5,926,800
Loss on extinguishment of debt	0	(24,517)	$ 0
Term Loan	$ 500,000
8 1/4% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total Redemption Amount		317,500
7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.375%
7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	7.125%
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes		988,940
Debt instrument, stated interest rate	3.80%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes		690,912
Debt instrument, stated interest rate	4.90%
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,900,000
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	853,000	165,000
Note payable	14,309	16,375
Total debt	7,117,788	5,928,878
Term Loan	498,274	0
Carrying Amount [Member] | 7 3/8% Senior Notes due 2020 [Member]
Debt Instrument [Line Items]
Senior notes	196,574	195,997
Carrying Amount [Member] | 7 1/8% Senior Notes due 2021 [Member]
Debt Instrument [Line Items]
Senior notes	395,365	394,668
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,996,831	1,996,507
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,482,451	1,480,479
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	989,932	988,940
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,052	$ 690,912

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Loss on extinguishment of debt	$ 0	$ (24,517,000)	$ 0
Aggregate amount of lender commitments on credit facility	2,750,000,000
Maximum borrowing capacity	$ 4,000,000,000
Line of credit facility, commitment fee percentage, per annum	0.225%
Line of Credit Facility, Covenant Terms	0.65
Proceeds from issuance of Senior Notes	$ 0	1,681,834,000	1,479,375,000
Repayments of Lines of Credit	1,313,000,000	1,805,000,000	$ 1,290,000,000
Current portion of long-term debt	2,144,000	2,078,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,900,000,000
Credit Facility [Domain]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.90%
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable	$ 22,000,000
Loan period, in years	10 years
Debt instrument, stated interest rate	3.14%
Debt instrument, maturity date	Feb. 26, 2022
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Apr. 15, 2023
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes		988,940,000
Debt instrument, stated interest rate	3.80%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes		690,912,000
Debt instrument, stated interest rate	4.90%
8 1/4% Senior Notes due 2019 [Member]
Debt Instrument [Line Items]
Total Redemption Amount		317,500,000
Loans Payable [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	1.80%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 853,000,000	165,000,000
Notes Payable	14,309,000	16,375,000
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,996,831,000	1,996,507,000
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,482,451,000	1,480,479,000
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	989,932,000	988,940,000
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,052,000	$ 690,912,000

Long-Term Debt - Summary of Mat

Long-Term Debt - Summary of Maturity Dates, Semi-Annual Interest Payment Dates, and Optional Redemption Periods Of Outstanding Senior Note Obligations (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)
2020 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 200,000
Maturity date	Oct. 1, 2020
Interest Payment Dates	April 1, Oct 1
Decreasing call premium redemption period	Oct. 1, 2015
Make-whole redemption period	Oct. 1, 2015
2021 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 400,000
Maturity date	Apr. 1, 2021
Interest Payment Dates	April 1, Oct 1
Decreasing call premium redemption period	Apr. 1, 2016	[1]
Make-whole redemption period	Apr. 1, 2016	[2]
2022 Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 2,000,000
Maturity date	Sep. 15, 2022
Interest Payment Dates	March 15,  Sep 15
Decreasing call premium redemption period	Mar. 15, 2017	[1]
Make-whole redemption period	Mar. 15, 2017	[2]
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,500,000
Maturity date	Apr. 15, 2023
Interest Payment Dates	April 15, Oct 15
Make-whole redemption period	Jan. 15, 2023	[2]
Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,000,000
Maturity date	Jun. 1, 2024
Interest Payment Dates	June 1, Dec 1
Make-whole redemption period	Mar. 1, 2024	[2]
Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 700,000
Maturity date	Jun. 1, 2044
Interest Payment Dates	June 1, Dec 1
Make-whole redemption period	Dec. 1, 2043	[2]
[1]	On or after these dates, the Company has the option to redeem all or a portion of its senior notes of the applicable series 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 of the applicable series at the “make-whole” redemption prices or amounts specified in the Indentures plus any accrued and unpaid interest to the date of redemption.

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Current tax provision, Federal	$ 0	$ 0	$ 6,193
Current tax provision, State	24	20	16
Total current income tax provision	24	20	6,209
Deferred tax provision, Federal	(140,578)	527,315	403,002
Deferred tax provision, State	(40,863)	57,362	39,619
Total deferred income tax provision (benefit)	(181,441)	584,677	442,621
Provision (benefit) for income taxes	$ (181,417)	$ 584,697	$ 448,830

Income Taxes - Schedule of Prov

Income Taxes - Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Expected income tax expense (benefit) based on US statutory tax rate of 35%	$ (187,280)	$ 546,713	$ 424,567
State income taxes, net of federal benefit	(16,219)	42,169	25,838
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	13,503	4,389	0
Effect of differing statutory tax rate in Canada	5,239	(1,900)	0
Other, net	3,340	(6,674)	(1,575)
Provision (benefit) for income taxes	$ (181,417)	$ 584,697	$ 448,830
Federal statutory income tax rate	35.00%

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards, Noncurrent	$ 398,024	$ 60,904
Deferred tax assets, Non-cash losses on derivatives, Noncurrent	17,892	4,899
Deferred tax assets, Alternative minimum tax carryforwards, Noncurrent	40,796	38,715
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	32,910	22,255
Deferred Tax Assets, Other	11,048	8,920
Total noncurrent deferred tax assets	500,670	135,693
Deferred Tax Assets, Valuation Allowance	(17,892)	(4,389)
Deferred Tax Assets, Net, Noncurrent	482,778	131,304
Deferred tax liabilities, Property and equipment, Noncurrent	(2,528,125)	(2,254,343)
Deferred Tax Liabilities Unrealized Gains on Derivatives, noncurrent	(38,452)	(30,269)
Deferred tax liabilities, Non-cash gains on derivatives, Noncurrent	(4,158)	(132,356)
Deferred Tax Liabilities, Other	(2,271)	(1,132)
Total noncurrent deferred tax liabilities	(2,573,006)	(2,418,100)
Net noncurrent deferred tax liabilities	$ (2,090,228)	$ (2,286,796)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 2,630,000
Alternative minimum tax credit carryforward	41,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	13,503	$ 4,389	$ 0
Deferred Tax Assets, Valuation Allowance	(17,892)	$ (4,389)
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	865,000
Oklahoma [Member]
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 2,120,000

Lease Commitments - Lease Commi

Lease Commitments - Lease Commitments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Lease expenses associated with operating leases	$ 9,600	$ 8,000	$ 3,000
2,014	3,348
2,015	1,327
2,016	979
2,017	291
2,018	210
Thereafter	3,105
Total obligations	$ 9,260

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date	$ 422
Drilling commitments 2016	200
Drilling commitments 2017	136
Drilling commitments 2018	62
Drilling commitments 2019	24
Damages claimed related to contingency matter	200
Legal proceedings recorded as a liability under other noncurrent liabilities	$ 6.1	$ 2.9
Future Drilling Commitments End Date	2019-12
Pipeline Transportation Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, end date	2,027
Future commitment, total	$ 1,000
Future commitment, due in 2016	215
Future commitment, due in 2017	212
Future commitment, due in 2018	207
Future commitment, due in 2019	154
Future commitment, due in 2020	47
Future commitments, thereafter	170
Non-operational Pipeline Transportation Commitments[Member]
Long-term Purchase Commitment [Line Items]
Future commitment, total	260
Fuel [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, total	$ 31

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)bbl
Related Party Transaction [Line Items]
Revenues from transactions with related party	$ 1,400,000	$ 95,128,000	$ 100,405,000
Due from affiliates		13,100,000
Due to Affiliate		300,000
Related party transaction, due to related party		1,200,000
Production expenses to affiliates	1,654,000	5,123,000	1,408,000
Total amount paid to related party	7,700,000	58,200,000	48,500,000
Due to affiliates		5,600,000
Amount charged to affiliate for aircraft use	9,600	51,000	55,000
Amount charged to company by affiliate for aircraft use	236,000	97,000	$ 51,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Number of barrels purchased from affiliate | bbl			30,000
Purchases from transactions with related party			$ 3,000,000
Expenses from transactions with related party	8,800,000	1,800,000
Capitalized costs	2,600,000	5,900,000	5,700,000
Production expenses to affiliates	1,700,000	5,100,000	1,400,000
Total amount paid to related party	9,200,000	1,900,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	500,000	800,000	1,300,000
Due to affiliates	52,000	133,000
Revenues paid to related party	700,000	1,700,000	2,300,000
Due from affiliates	106,000	207,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	221,000	34,000	238,000
Total amount received from related party	$ 33,000	39,000	379,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party		$ 95,100,000	$ 100,400,000

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation	$ 51,834	$ 54,353	$ 39,890

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 23.6	$ 58.2	$ 49.4
Unrecognized compensation expense related to non-vested	$ 67
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 2 months
Restricted stock [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years	1 year
Restricted stock [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grants vest over periods, in years	3 years
2013 Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common stock available for issue	19,680,072
2013 Plan [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant	17,028,213

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Non-vested shares, beginning balance	2,678,764	2,714,312	3,258,924
Granted shares	1,462,534	1,424,764	522,518
Vested shares	(555,517)	(1,007,166)	(929,618)
Forfeited shares	(336,170)	(453,146)	(137,512)
Non-vested shares, ending balance	3,249,611	2,678,764	2,714,312
Non-vested, weighted average grant-date fair value, beginning of period	$ 49.40	$ 37.50	$ 31.64
Granted, weighted average grant-date fair value	46.65	61.11	48.98
Vested, weighted average grant-date fair value	48.07	35.91	23.65
Forfeited, weighted average grant-date fair value	51.23	44.90	35.96
Non-vested, weighted average grant-date fair value, end of period	$ 48.20	$ 49.40	$ 37.50

Accumulated Other Comprehensi69

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Foreign Currency [Abstract]
Foreign currency translation adjustments		$ (2,969)	$ (385)	$ 0
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	[1]	0	0
Other Comprehensive Income (Loss), Net of Tax		(2,969)	(385)	0
Accumulated other comprehensive loss		$ (3,354)	$ (385)	$ 0
[1]	A valuation allowance has been recognized against deferred tax assets associated with losses generated by the Company's Canadian operations, thereby resulting in no income taxes on other comprehensive loss.

Property Dispositions - Additio

Property Dispositions - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets and other	$ 34,008	$ 129,388	$ 28,420
Proceeds from sale of non-producing leasehold	25,900
Gain (Loss) on disposition of non-producing leasehold	$ 20,500
Niobrara [Domain]
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets and other		30,300
Northwest Cana [Member]
Property Acquisition And Dispositions [Line Items]
Proceeds from sale of assets and other		$ 85,800

Crude Oil and Natural Gas Pro71

Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil and natural gas sales	$ 2,552,531	$ 4,203,022	$ 3,573,431
Production expenses	(348,897)	(352,472)	(282,197)
Production taxes and other expenses	(200,637)	(349,760)	(298,787)
Exploration Expense	(19,413)	(50,067)	(34,947)
Depreciation, depletion, amortization and accretion	(1,722,336)	(1,338,351)	(953,796)
Property impairments	(402,131)	(616,888)	(220,508)
Income tax benefit (provision)	33,680	(559,311)	(659,783)
Results from crude oil and natural gas producing activities	$ (107,203)	$ 936,173	$ 1,123,413

Crude Oil and Natural Gas Pro72

Crude Oil and Natural Gas Property Information - Schedule of Costs Incurred in Oil and Gas Property Acquisition Exploration and Development Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 557	$ 48,917	$ 16,604
Property Acquisition Costs - Unproved	168,492	409,529	546,881
Total property acquisition costs	169,049	458,446	563,485
Exploration Costs	241,523	863,606	687,767
Development Costs	2,148,530	3,670,448	2,549,203
Total	$ 2,559,102	$ 4,992,500	$ 3,800,455

Crude Oil and Natural Gas Pro73

Crude Oil and Natural Gas Property Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Exploration costs included in asset retirement costs	$ 3.3	$ 1.2	$ 1.8
Development costs included in asset retirement costs	$ 19.5	$ 19.1	$ 6

Crude Oil and Natural Gas Pro74

Crude Oil and Natural Gas Property Information - Schedule of Aggregate Capitalized Costs Relates to Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	Dec. 31, 2015	Dec. 31, 2014
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 19,520,724	$ 17,045,967
Unproved crude oil and natural gas properties	682,988	966,080
Total	20,203,712	18,012,047
Less accumulated depreciation, depletion and amortization	(6,374,218)	(4,601,864)
Net capitalized costs	$ 13,829,494	$ 13,410,183

Crude Oil and Natural Gas Pro75

Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2015USD ($)Well	Dec. 31, 2014USD ($)Well	Dec. 31, 2013USD ($)Well
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Capitalized Exploratory Well Costs that Have Been Capitalized for Period Greater than One Year	$ 1,700
Number Of Wells With Capitalized Exploratory Well Costs Suspended One Year Beyond Completion Of Drilling	3
Suspended Well Costs Incurred		$ 100	$ 1,600
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 93,421	152,775	92,699
Additions to capitalized exploratory well costs pending determination of proved reserves	132,806	627,853	548,933
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(160,779)	(671,618)	(479,507)
Capitalized exploratory well costs charged to expense	(6,051)	(15,589)	(9,350)
Balance at December 31	$ 59,397	$ 93,421	$ 152,775
Number of wells | Well	73	119	67

Supplemental Crude Oil and Na76

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015$ / Barrels	Dec. 31, 2015MBoe	Dec. 31, 2015MBbls	Dec. 31, 2015MMcf	Dec. 31, 2014$ / bbl$ / McfMBoeMBblsMMcf	Dec. 31, 2013$ / bbl$ / McfMBoeMBblsMMcf
Reserve Quantities [Line Items]
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%					99.00%	99.00%
Percent of proved crude oil reserve estimates prepared by external reserve engineers	99.00%
Percent of proved natural gas reserve estimates prepared by external reserve engineers	97.00%
Revisions of previous estimates | MBoe			(297,198)			(107,949)	(96,054)
Extensions, discoveries and other additions | MBoe			253,173			440,621	444,654
Discount factor utilized as standardized measure for future net cash flows	10.00%
Crude Oil [Member]
Reserve Quantities [Line Items]
Weighted average price utilized in computation of future cash inflows		41.63				84.54	91.50
Crude Oil [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	47.00%
Revisions of previous estimates | MBbls				(246,840)		(67,151)	(55,783)
Extensions, discoveries and other additions | MBbls				134,764		239,526	267,009
Natural Gas [Member]
Reserve Quantities [Line Items]
Percentage change in average SEC price	41.00%
Revisions of previous estimates | MMcf					(302,143)	(244,783)	(241,623)
Extensions, discoveries and other additions | MMcf					710,453	1,206,569	1,065,870
Weighted average price utilized in computation of future cash inflows		2.35				6.06	5.36
Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe			98
Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				197
Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				65
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions				75,000	124,000
Extensions, discoveries and other additions | MBoe			96,000
SCOOP [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions				36,000	340,000
Extensions, discoveries and other additions | MBoe			93,000
Northwest Cana [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions				20,000	222,000
Extensions, discoveries and other additions | MBoe			57,000
Price Driven [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe			251
Price Driven [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				391
Price Driven [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				185
Production [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe			42
Production [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				125
Production [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				63

Supplemental Crude Oil and Na77

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015$ / Barrels	Dec. 31, 2015MBoe	Dec. 31, 2015MBbls	Dec. 31, 2015MMcf	Dec. 31, 2014$ / BarrelsMBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf
Reserve Quantities [Line Items]
Percentage of discounted future net cash flows prepared by external reserve engineers	99.00%					99.00%	99.00%
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period, Total			1,351,091			1,084,125	784,677
Revisions of previous estimates, Total			(297,198)			(107,949)	(96,054)
Extensions, discoveries and other additions, Total			253,173			440,621	444,654
Production, Total			(80,926)			(63,579)	(49,610)
Sales of minerals in place, Total			(329)			(3,227)	0
Purchases of minerals in place, Total			0			1,100	458
Proved reserves at end of period, Total			1,225,811			1,351,091	1,084,125
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	97.00%
Natural Gas [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels		2.58				4.35
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf					2,908,386	2,078,020	1,341,084
Revisions of previous estimates | MMcf					(302,143)	(244,783)	(241,623)
Extensions, discoveries and other additions | MMcf					710,453	1,206,569	1,065,870
Production | MMcf					(164,454)	(114,295)	(87,730)
Sales of minerals in place | MMcf					(456)	(18,623)	0
Purchases of minerals in place | MMcf					0	1,498	419
Proved reserves at end of period | MMcf					3,151,786	2,908,386	2,078,020
Crude Oil [Member]
Reserve Quantities [Line Items]
Twelve month average SEC price | $ / Barrels		50.28				94.99
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls				866,360		737,788	561,163
Revisions of previous estimates | MBbls				(246,840)		(67,151)	(55,783)
Extensions, discoveries and other additions | MBbls				134,764		239,526	267,009
Production | MBbls				(53,517)		(44,530)	(34,989)
Sales of minerals in place | MBbls				(253)		(123)	0
Purchases of minerals in place | MBbls				0		850	388
Proved reserves at end of period | MBbls				700,514		866,360	737,788
Northwest Cana [Member]
Changes in Proved Reserves [Roll Forward]
Extensions, discoveries and other additions				20,000	222,000
Extensions, discoveries and other additions, Total			57,000

Supplemental Crude Oil and Na78

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	Dec. 31, 2015MBoeMBblsMMcf	Dec. 31, 2014MBoeMBblsMMcf	Dec. 31, 2013MBoeMBblsMMcf	Dec. 31, 2012MMcf
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) | MBoe	525,188	502,479	406,792
Proved Undeveloped Reserve (MBOE) | MBoe	700,623	848,612	677,333
Total Proved Reserves (MBOE) | MBoe	1,225,811	1,351,091	1,084,125
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MBbls	326,798	342,137	278,630
Proved Undeveloped Reserve (Volume) | MBbls	373,716	524,223	459,158
Total Proved Reserves (Volume) | MBbls	700,514	866,360	737,788
Natural Gas [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MMcf	1,190,343	962,051	768,969
Proved Undeveloped Reserve (Volume) | MMcf	1,961,443	1,946,335	1,309,051
Total Proved Reserves (Volume) | MMcf	3,151,786	2,908,386	2,078,020	1,341,084

Supplemental Crude Oil and Na79

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 36,551,672	$ 90,867,459	$ 78,646,274
Future production costs	(10,869,493)	(25,799,221)	(21,333,460)
Future development and abandonment costs	(6,935,958)	(12,842,174)	(10,250,789)
Future income taxes	(3,717,612)	(13,800,737)	(12,447,127)
Future net cash flows	15,028,609	38,425,327	34,614,898
10% annual discount for estimated timing of cash flows	(8,552,325)	(19,992,293)	(18,319,131)
Standardized measure of discounted future net cash flows	$ 6,476,284	$ 18,433,034	$ 16,295,767	$ 11,180,357

Supplemental Crude Oil and Na80

Supplemental Crude Oil and Natural Gas Information - Changes in Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
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	$ 18,433,034	$ 16,295,767	$ 11,180,357
Extensions, discoveries and improved recoveries, less related costs	1,091,283	5,516,528	6,613,665
Revisions of previous quantity estimates	(2,156,028)	(1,755,366)	(1,765,300)
Changes in estimated future development and abandonment costs	5,008,731	476,665	1,942,585
Sales of Minerals in Place	(7,768)	(3,196)
Purchases of minerals in place			12,012
Net change in prices and production costs	(16,111,142)	(1,925,349)	263,541
Accretion of discount	1,843,303	1,629,576	1,118,036
Sales of crude oil and natural gas produced, net of production costs	(2,002,997)	(3,500,790)	(2,992,447)
Development costs incurred during the period	1,394,584	2,466,748	1,210,223
Change in timing of estimated future production and other	(3,844,259)	(309,902)	464,111
Change in income taxes	2,827,543	(457,647)	(1,751,016)
Net change	(11,956,750)	2,137,267	5,115,410
Standardized measure of discounted future net cash flows at end of year	$ 6,476,284	$ 18,433,034	$ 16,295,767

Quarterly Financial Data - Sche

Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Loss on extinguishment of debt																	$ 0	$ 24,517	$ 0
Extinguishment of Debt, Gain (Loss), Net of Tax																		$ 15,400
Extinguishment of Debt, Gain (Loss), Per Share, Net of Tax																		$ 0.04
Cash Proceeds from Liquidated Derivatives									$ 433,000									$ 433,000
Cash Proceeds from Liquidated Derivatives, after tax									$ 273,000
Cash Proceeds from Liquidated Derivatives, per share									$ 0.74
Total revenues	$ 575,480	[1]	$ 682,669	[1]	$ 796,374	[1]	$ 625,644	[1]	$ 1,297,700	[1],[2]	$ 1,645,328	[3]	$ 886,095	[1]	$ 972,495	[1]	2,680,167	4,801,618	3,421,807
Gain (loss) on derivative instruments, net	16,540	[1]	46,527	[1]	(4,737)	[1]	32,755	[1]	387,958	[1],[2]	473,999	[1]	(262,524)	[1]	(39,674)	[1]	91,085	559,759	(191,751)
Property impairments	81,001	[4]	96,697	[4]	76,872	[4]	147,561	[4]	393,803	[4]	85,561	[4]	79,316	[4]	58,208	[4]	402,131	616,888	220,508
Income from operations	(142,816)		(52,356)		82,447		(111,276)		265,228	[2]	944,897		236,394		421,317		(224,001)	1,867,836	1,445,767
Net income (loss)	$ (139,677)		$ (82,423)		$ 403		$ (131,971)		$ 114,048	[2]	$ 533,521		$ 103,538		$ 226,234		$ (353,668)	$ 977,341	$ 764,219
Net income per share: Basic	$ (0.38)		$ (0.22)		$ 0		$ (0.36)		$ 0.31	[2]	$ 1.45	[3]	$ 0.28		$ 0.61		$ (0.96)	$ 2.65	$ 2.08
Net income per share: Diluted	$ (0.38)		$ (0.22)		$ 0		$ (0.36)		$ 0.31	[2]	$ 1.44	[3]	$ 0.28		$ 0.61		$ (0.96)	$ 2.64	$ 2.07
[1]	Gains and losses on mark-to-market derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Derivative gains and losses have been shown separately to illustrate the fluctuations in revenues that are attributable to the Company’s derivative instruments. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
[2]	Balances for the fourth quarter of 2014 include $433 million of pre-tax gains ($273 million after tax, or $0.74 per basic and diluted share) recognized from crude oil derivative contracts that were settled prior to their contractual maturities.
[3]	The 2014 third quarter includes a $24.5 million pre-tax ($15.4 million after tax, or $0.04 per basic and diluted share) loss on extinguishment of debt as discussed in Note 7. Long-Term Debt.
[4]	Property impairments have been shown separately to illustrate the fluctuations in income (loss) that are attributable to write downs of the Company's assets. Commodity price fluctuations each quarter can result in significant changes in estimated future cash flows and resulting impairments, which affects comparability between periods.