Continental Resources Inc (CLR) 10-K 19 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2,018
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 Emerging Growth Company	false
Entity Small Business	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		376,014,925
Entity Public Float			$ 5.6

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Current assets:
Cash and cash equivalents	$ 282,749	$ 43,902
Receivables:
Crude oil and natural gas sales	644,107	671,665
Affiliated parties	73	63
Joint interest and other, net	368,235	426,585
Derivative assets	15,612	2,603
Inventories	88,544	97,406
Prepaid expenses and other	13,041	9,501
Total current assets	1,412,361	1,251,725
Net property and equipment, based on successful efforts method of accounting	13,869,800	12,933,789
Other noncurrent assets	15,786	14,137
Total assets	15,297,947	14,199,651
Current liabilities:
Accounts payable trade	717,560	692,908
Revenues and royalties payable	400,567	374,831
Payables to affiliated parties	203	143
Accrued liabilities and other	266,819	260,074
Current portion of long-term debt	2,360	2,286
Total current liabilities	1,387,509	1,330,242
Long-term debt, net of current portion	5,765,989	6,351,405
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,574,436	1,259,558
Asset retirement obligations, net of current portion	136,986	111,794
Other noncurrent liabilities	11,166	15,449
Total other noncurrent liabilities	1,722,588	1,386,801
Commitments and contingencies (Note 11)
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; 376,021,575 shares issued and outstanding at December 31, 2018; 375,219,769 shares issued and outstanding at December 31, 2017	3,760	3,752
Additional paid-in capital	1,434,823	1,409,326
Accumulated other comprehensive loss	415	307
Retained earnings	4,706,135	3,717,818
Total shareholders’ equity attributable to Continental Resources	6,145,133	5,131,203
Noncontrolling interests	276,728	0
Total equity	6,421,861	5,131,203
Total liabilities and equity	$ 15,297,947	$ 14,199,651

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
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	1,000,000,000
Common stock, shares issued	376,021,575	375,219,769
Common stock, outstanding	376,021,575	375,219,769

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Revenues:
Crude oil and natural gas sales	$ 4,678,722	$ 2,982,966	$ 2,026,958
Gain (loss) on crude oil and natural gas derivatives, net	(23,930)	91,647	(71,859)
Crude oil and natural gas service operations	54,794	46,215	25,174
Total revenues	4,709,586	3,120,828	1,980,273
Operating costs and expenses:
Production expenses	390,423	324,214	289,289
Production taxes	353,140	208,278	142,388
Transportation expenses	191,587	0	0
Exploration expenses	7,642	12,393	16,972
Crude oil and natural gas service operations	21,639	16,880	11,386
Depreciation, depletion, amortization and accretion	1,859,327	1,674,901	1,708,744
Property impairments	125,210	237,370	237,292
General and administrative expenses	183,569	191,706	169,580
Litigation settlement	0	59,600	0
Net gain on sale of assets and other	(16,671)	(53,915)	(307,844)
Total operating costs and expenses	3,115,866	2,671,427	2,267,807
Income (loss) from operations	1,593,720	449,401	(287,534)
Other income (expense):
Interest expense	(293,032)	(294,495)	(320,562)
Loss on extinguishment of debt	(7,133)	(554)	(26,055)
Other	3,247	1,715	1,697
Total other income (expense)	(296,918)	(293,334)	(344,920)
Income (loss) before income taxes	1,296,802	156,067	(632,454)
(Provision) benefit for income taxes	(307,102)	633,380	232,775
Net income (loss)	989,700	789,447	(399,679)
Net income (loss) attributable to noncontrolling interests	1,383	0	0
Net income (loss) attributable to Continental Resources	$ 988,317	$ 789,447	$ (399,679)
Basic net income (loss) per share (in dollars per share)	$ 2.66	$ 2.13	$ (1.08)
Diluted net income (loss) per share (in dollars per share)	$ 2.64	$ 2.11	$ (1.08)
Foreign currency translation adjustments	$ 108	$ 567	$ 3,094
Other Comprehensive Income (Loss), Net of Tax	108	567	3,094
Comprehensive Income (Loss), Net of Tax, Consolidated	989,808	790,014	(396,585)
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	1,383	0	0
Comprehensive Income (Loss), Net of Tax, Attributable to Continental Resources	$ 988,425	$ 790,014	$ (396,585)

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Thousands	Total	Common stock	Additional paid-in capital	Accumulated Other Comprehensive Loss	Retained earnings	Continental Resources Shareholders' Equity	Noncontrolling Interests
Increase (Decrease) in Equity [Roll Forward]
Total equity	$ 4,668,900
Balance at Dec. 31, 2015		$ 3,730	$ 1,345,624	$ (3,354)	$ 3,322,900	$ 4,668,900
Balance, shares at Dec. 31, 2015		372,959,080
Increase (Decrease) in Equity [Roll Forward]
Net income (loss) attributable to Continental Resources	(399,679)				(399,679)	(399,679)
Net income (loss) attributable to noncontrolling interests	0
Net income (loss)	(399,679)
Other Comprehensive Income (Loss), Net of Tax	3,094			3,094		3,094
Equity transaction costs	0
Stock-based compensation	48,084		48,084			48,084
Excess Tax Benefit from Share-based Compensation	(9,828)		(9,828)			(9,828)
Restricted stock:
Issued	20	$ 20	0			20
Issued, shares		2,064,508
Repurchased and canceled	(8,593)	$ (3)	(8,590)			(8,593)
Repurchased and canceled, shares		(337,981)
Forfeited	(2)	$ (2)				(2)
Forfeited, shares		(193,250)
Balance at Dec. 31, 2016		$ 3,745	1,375,290	(260)	2,923,221	4,301,996
Balance, shares at Dec. 31, 2016		374,492,357
Increase (Decrease) in Equity [Roll Forward]
Total equity	4,301,996
Cumulative Effect on Retained Earnings, Tax					5,150
Net income (loss) attributable to Continental Resources	789,447				789,447	789,447
Net income (loss) attributable to noncontrolling interests	0
Net income (loss)	789,447
Other Comprehensive Income (Loss), Net of Tax	567			567		567
Equity transaction costs	0
Stock-based compensation	45,854		45,854			45,854
Cumulative Effect on Retained Earnings, Net of Tax	5,150					5,150
Restricted stock:
Issued	16	$ 16	0			16
Issued, shares		1,585,870
Repurchased and canceled	(11,821)	$ (3)	(11,818)			(11,821)
Repurchased and canceled, shares		(259,729)
Forfeited	(6)	$ (6)				(6)
Forfeited, shares		(598,729)
Balance at Dec. 31, 2017	$ 5,131,203	$ 3,752	1,409,326	307	3,717,818	5,131,203
Balance, shares at Dec. 31, 2017	375,219,769	375,219,769
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests	$ 0
Total equity	5,131,203
Net income (loss) attributable to Continental Resources	988,317				988,317	988,317
Net income (loss) attributable to noncontrolling interests	1,383						$ 1,383
Net income (loss)	989,700
Other Comprehensive Income (Loss), Net of Tax	108			108		108
Equity transaction costs	(4,838)		(4,838)			(4,838)
Stock-based compensation	47,223		47,223			47,223
Contributions from noncontrolling interests	277,238						277,238
Distributions to noncontrolling interests	(1,893)						(1,893)
Restricted stock:
Issued	14	$ 14	0			14
Issued, shares		1,390,914
Repurchased and canceled	(16,891)	$ (3)	(16,888)			(16,891)
Repurchased and canceled, shares		(310,822)
Forfeited	(3)	$ (3)				(3)
Forfeited, shares		(278,286)
Balance at Dec. 31, 2018	$ 6,145,133	$ 3,760	$ 1,434,823	$ 415	$ 4,706,135	$ 6,145,133
Balance, shares at Dec. 31, 2018	376,021,575	376,021,575
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests	$ 276,728						$ 276,728
Total equity	$ 6,421,861

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net income (loss)	$ 989,700	$ 789,447	$ (399,679)
Adjustments to reconcile net income (loss) to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	1,859,118	1,670,838	1,709,567
Property impairments	125,210	237,370	237,292
Non-cash (gain) loss on derivatives, net	(13,009)	(58,031)	156,621
Stock-based compensation	47,236	45,868	48,098
Tax benefit from US tax reform legislation	0	(713,655)	0
Provision (benefit) for deferred income taxes from operations	314,878	88,056	(209,836)
Tax deficiency from stock-based compensation	0	0	9,828
Dry hole costs	147	176	4,866
Litigation settlement	0	59,600	0
Net gain on sale of assets and other	(16,671)	(55,124)	(304,489)
Loss on extinguishment of debt	7,133	554	26,055
Other, net	16,558	12,592	9,812
Changes in assets and liabilities:
Accounts receivable	94,765	(329,811)	(158,383)
Inventories	7,735	14,517	(17,836)
Other current assets	(3,539)	1,038	968
Accounts payable trade	9,274	137,339	(14,404)
Revenues and royalties payable	24,010	158,982	30,455
Accrued liabilities and other	(4,162)	21,368	(883)
Other noncurrent assets and liabilities	(2,375)	(2,018)	(2,133)
Net cash provided by operating activities	3,456,008	2,079,106	1,125,919
Cash flows from investing activities:
Exploration and development	(2,840,880)	(1,931,942)	(1,154,131)
Purchase of producing crude oil and natural gas properties	(31,579)	(8,446)	(5,008)
Purchase of other property and equipment	(42,171)	(12,810)	(5,375)
Proceeds from sale of assets	54,458	144,353	631,549
Net cash used in investing activities	(2,860,172)	(1,808,845)	(532,965)
Cash flows from financing activities:
Credit facility borrowings	2,024,000	1,302,000	1,691,000
Repayment of credit facility	(2,212,000)	(2,019,000)	(1,639,000)
Proceeds from issuance of Senior Notes	0	990,000	0
Redemption of Senior Notes	(400,000)	0	(600,000)
Premium on redemption of Senior Notes	(6,700)	0	(19,168)
Repayment of other debt	(2,286)	(502,214)	(2,144)
Debt issuance costs	(5,535)	(1,999)	(40)
Equity transaction costs	(4,838)	0	0
Contributions from noncontrolling interests	267,920	0	0
Distributions to noncontrolling interests	(604)	0	0
Repurchase of restricted stock for tax withholdings	(16,891)	(11,821)	(8,593)
Tax deficiency from stock-based compensation	0	0	(9,828)
Net cash used in financing activities	(356,934)	(243,034)	(587,773)
Effect of exchange rate on cash and cash equivalents	(55)	32	(1)
Net change in cash and cash equivalents	238,847	27,259	5,180
Cash and cash equivalents at beginning of period	43,902	16,643	11,463
Cash and cash equivalents at end of period	$ 282,749	$ 43,902	$ 16,643

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2018
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. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. 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 Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations. Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements. 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 periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are 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. 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, 2018 , the Company had cash deposits in excess of federally insured amounts of approximately $280.7 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 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. The Company’s allowance for doubtful accounts totaled $2.4 million and $2.2 million as of December 31, 2018 and 2017 , respectively, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets. Concentration of credit risk The Company is subject to credit risk resulting from the concentration of its crude oil and natural gas receivables with significant purchasers. For the year ended December 31, 2018 , sales to the Company’s largest purchaser accounted for approximately 12% of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2018 . The Company generally 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, pipeline imbalances, 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 net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2018 and 2017 consisted of the following: December 31, In thousands 2018 2017 Tubular goods and equipment $ 14,623 $ 14,946 Crude oil 73,921 82,460 Total $ 88,544 $ 97,406 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. 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 but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related 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 and recycling 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 and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40 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 and related disposal of facilities on its crude oil and natural gas properties. The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2016 through December 31, 2018 : In thousands 2018 2017 2016 Asset retirement obligations at January 1 $ 114,406 $ 96,178 $ 102,909 Accretion expense 6,985 5,886 6,086 Revisions (1) 13,075 7,801 (12,755 ) Plus: Additions for new assets 9,070 6,884 2,692 Less: Plugging costs and sold assets (2,176 ) (2,343 ) (2,754 ) Total asset retirement obligations at December 31 $ 141,360 $ 114,406 $ 96,178 Less: Current portion of asset retirement obligations at December 31 (2) 4,374 2,612 1,742 Non-current portion of asset retirement obligations at December 31 $ 136,986 $ 111,794 $ 94,436 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties. (2) Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets. As of December 31, 2018 and 2017 , net property and equipment on the consolidated balance sheets included $57.7 million and $40.0 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. Impairment losses for unproved properties are generally 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 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 aggregate capitalized costs of $51.2 million and $58.2 million (net of accumulated amortization of $62.5 million and $51.8 million ) relating to its long-term debt at December 31, 2018 and 2017 , respectively. Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $45.1 million and $55.0 million at December 31, 2018 and 2017 , respectively, and are reflected as a reduction of “Long-term debt, net of current portion” on the consolidated balance sheets. Unamortized capitalized costs associated with the Company’s revolving credit facility totaled $6.1 million and $3.2 million at December 31, 2018 and 2017 , respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2018 , 2017 and 2016 , the Company recognized amortization expense associated with capitalized debt issuance costs of $9.3 million , $9.1 million and $9.8 million , respectively, which are reflected in “Interest expense” on 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). Gains and losses on crude oil and natural gas derivatives are reflected in the caption “ Gain (loss) on crude oil and natural gas derivatives, net .” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.” 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, 2018 and 2017 . 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 $0.3 million , $0.4 million , and $1.0 million for the years ended December 31, 2018 , 2017 , and 2016 , 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 attributable to Continental Resources Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings 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 attributable to the Company for the years ended December 31, 2018 , 2017 and 2016 . Year ended December 31, In thousands, except per share data 2018 2017 2016 Net income (loss) attributable to Continental Resources (numerator) (1) $ 988,317 $ 789,447 $ (399,679 ) Weighted average shares (denominator): Weighted average shares - basic 371,854 371,066 370,380 Non-vested restricted stock (2) 2,984 2,702 — Weighted average shares - diluted 374,838 373,768 370,380 Net income (loss) per share attributable to Continental Resources: (1) Basic $ 2.66 $ 2.13 $ (1.08 ) Diluted $ 2.64 $ 2.11 $ (1.08 ) (1) The Company remeasured its deferred income tax assets and liabilities at year-end 2017 in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of $713.7 million ( $1.92 per basic share and $1.91 per diluted share) for 2017. See Note 9. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies—Litigation , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share). (2) For the year ended December 31, 2016, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation. Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada are immaterial. 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 income” within equity on the consolidated balance sheets and “Other comprehensive income, net of tax” in the consolidated statements of comprehensive income (loss). Adoption of new accounting pronouncements in 2018 Revenue recognition and presentation – In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) , which superseded nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required. See Note 8. Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance. New accounting pronouncements not yet adopted at December 31, 2018 Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard became effective for interim and annual reporting periods beginning after December 15, 2018. The Company adopted the new standard on January 1, 2019 on a prospective basis using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting lease assets and lease liabilities recognized by the Company on the adoption date totaled approximately $19 million , representing minimum payment obligations associated with drilling rig commitments, surface use agreements, equipment, and other leases with contractual durations in excess of one year. Such leases, all of which are operating leases, had a weighted average remaining life and discount rate of 5.4 years and 4.5% , respectively, as of January 1, 2019. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company has elected not to apply the recognition requirements of ASU 2016-02 to leases with durations of twelve months or less. No cumulative-effect adjustment to retained earnings was recognized upon adoption of the new lease standard. The value of lease assets and lease liabilities recognized under ASU 2016-02 will change with the passage of time and from changes in the nature, timing, and extent of the Company's contractual lease arrangements in effect from period to period. As a result, the lease assets and liabilities recognized by the Company as of January 1, 2019 may not be indicative of amounts to be recognized in future periods. The Company continues to work on finalizing its implementation of procedures to comply with the new disclosure requirements prescribed by ASU 2016-02. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2016 Supplemental cash flow information: Cash paid for interest $ 270,927 $ 281,058 $ 316,116 Cash paid for income taxes — 2 2 Cash received for income tax refunds 7,893 257 174 Non-cash investing activities: Asset retirement obligation additions and revisions, net 22,145 14,685 (10,063 ) As of December 31, 2018 and 2017 , the Company had $317.5 million and $302.8 million , respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the consolidated balance sheets.

Net Property and Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2018 and 2017 . December 31, In thousands 2018 2017 Proved crude oil and natural gas properties $ 24,060,625 $ 21,362,199 Unproved crude oil and natural gas properties 291,564 365,413 Service properties, equipment and other 324,758 290,111 Total property and equipment 24,676,947 22,017,723 Accumulated depreciation, depletion and amortization (10,807,147 ) (9,083,934 ) Net property and equipment $ 13,869,800 $ 12,933,789

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2018 and 2017 : December 31, In thousands 2018 2017 Prepaid advances from joint interest owners $ 53,674 $ 34,511 Accrued compensation 69,338 65,308 Accrued production taxes, ad valorem taxes and other non-income taxes 52,105 40,611 Accrued interest 64,483 55,282 Accrued litigation settlement (see Note 11) 19,753 59,600 Current portion of asset retirement obligations 4,374 2,612 Other 3,092 2,150 Accrued liabilities and other $ 266,819 $ 260,074

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Crude oil and natural gas derivatives From time to time the Company has entered into crude oil and natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of crude oil and natural gas production. 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 crude oil and natural gas derivative instruments as hedges for accounting purposes and, as a result, marks such 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 crude oil and natural gas derivatives, net .” The Company's natural gas derivative contracts are settled based upon reported NYMEX Henry Hub settlement prices. The estimated fair value of derivatives 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 . With respect to a natural gas 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 natural gas 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. At December 31, 2018 , the Company had outstanding natural gas derivative contracts as set forth in the table below. The volumes reflected below represent an aggregation of multiple derivative contracts having similar remaining durations expected to be realized ratably over the reflected periods. At December 31, 2018 the Company had no outstanding crude oil derivative contracts. Floors Ceilings Period and Type of Contract MMBtus Swaps Weighted Average Price Range Weighted average price Range Weighted average price January 2019 - March 2019 Swaps - Henry Hub 4,950,000 $ 4.70 April 2019 - December 2019 Swaps - Henry Hub 95,425,000 $ 2.78 January 2019 - March 2019 Collars - Henry Hub 4,950,000 $ 4.25 $ 4.25 $5.50 - $5.58 $ 5.52 Crude oil and natural gas derivative gains and losses Cash receipts and payments in the following table reflect the gain or loss on derivative contracts which matured during the period, calculated as the difference between the contract price and the market settlement price of matured contracts. Non-cash gains and losses below represent the change in fair value of derivative instruments which continue to be held at period end and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the period. Year ended December 31, In thousands 2018 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ (36,939 ) $ 40,095 $ 88,823 Natural gas collars — (10,539 ) — Cash received (paid) on derivatives, net (36,939 ) 29,556 88,823 Non-cash gain (loss) on derivatives: Crude oil written call options — — 38 Natural gas fixed price swaps 7,527 18,960 (120,784 ) Natural gas collars 5,482 43,131 (39,936 ) Non-cash gain (loss) on derivatives, net 13,009 62,091 (160,682 ) Gain (loss) on crude oil and natural gas derivatives, net $ (23,930 ) $ 91,647 $ (71,859 ) Diesel fuel derivatives The Company previously entered into diesel fuel swap derivative contracts, all of which matured on or before December 31, 2017, to economically hedge against the variability in cash flows associated with purchases of diesel fuel for use in drilling activities. The Company did not designate its diesel fuel derivatives as hedges for accounting purposes and, as a result, marked the derivative instruments to fair value and recognized the changes in fair value in the consolidated statements of comprehensive income (loss) under the caption “Operating costs and expenses—Net gain on sale of assets and other.” Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the respective 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 diesel fuel derivatives held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the respective period. Year ended December 31, In thousands 2017 2016 Cash received on diesel fuel derivatives $ 2,845 $ 699 Non-cash gain (loss) on diesel fuel derivatives (4,060 ) 4,060 Gain (loss) on diesel fuel derivatives, net $ (1,215 ) $ 4,759 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”, as applicable. 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 presents the gross amounts of recognized natural gas derivative assets and liabilities, as applicable, 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 2018 2017 Commodity derivative assets: Gross amounts of recognized assets $ 16,789 $ 2,603 Gross amounts offset on balance sheet (1,177 ) — Net amounts of assets on balance sheet 15,612 2,603 Commodity derivative liabilities: Gross amounts of recognized liabilities (1,177 ) — Gross amounts offset on balance sheet 1,177 — Net amounts of liabilities on balance sheet $ — $ — 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 2018 2017 Derivative assets $ 15,612 $ 2,603 Noncurrent derivative assets — — Net amounts of assets on balance sheet 15,612 2,603 Derivative liabilities — — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — — Total derivative assets, net $ 15,612 $ 2,603

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
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 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 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 swap contracts, 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 swap contracts are calculated mainly using significant observable inputs (Level 2). Calculation of the fair values of collars 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, 2018 and 2017 . Fair value measurements at December 31, 2018 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 10,130 $ — $ 10,130 Collars — 5,482 — 5,482 Total $ — $ 15,612 $ — $ 15,612 Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603 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. Risk-adjusted probable and possible reserves may be taken into consideration when determining estimated future net cash flows and fair value when such reserves exist and are economically recoverable. 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 adjusted for differentials, 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 at December 31, 2018 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 strip prices through 2023 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of properties Up to 50 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management. For the years ended December 31, 2018 , 2017 , and 2016 , the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $18.0 million for 2018 , which reflect write-offs of various non-core properties in the North and South regions. Impairments of proved properties totaled $82.3 million for 2017 , which reflect fair value adjustments in the Arkoma Woodford field ( $81.2 million ) and various non-core properties in the North and South regions ( $1.1 million ). The impaired properties in 2017 were written down to their estimated fair value at the time of impairment of $72 million . Impairments of proved properties totaled $2.9 million for 2016 primarily related to non-core properties in the North region that were written down to their estimated fair value at the time of impairment of $0.7 million . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2018 , 2017 , and 2016 , 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 2018 2017 2016 Proved property impairments $ 18,037 $ 82,340 $ 2,895 Unproved property impairments 107,173 155,030 234,397 Total $ 125,210 $ 237,370 $ 237,292 Financial instruments not recorded at fair value The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2018 December 31, 2017 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Revolving credit facility $ — $ — $ 188,000 $ 188,000 Note payable 7,700 7,700 9,974 9,900 5% Senior Notes due 2022 1,598,404 1,590,900 1,997,576 2,040,000 4.5% Senior Notes due 2023 1,488,960 1,476,300 1,486,690 1,526,800 3.8% Senior Notes due 2024 993,151 947,200 992,036 988,800 4.375% Senior Notes due 2028 988,617 942,800 988,061 987,200 4.9% Senior Notes due 2044 691,517 618,800 691,354 679,900 Total debt $ 5,768,349 $ 5,583,700 $ 6,353,691 $ 6,420,600 The fair value of revolving credit facility borrowings 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 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”), the 4.375% Senior Notes due 2028 (“2028 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, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $39.4 million and $44.3 million at December 31, 2018 and 2017 , respectively, consists of the following. December 31, In thousands 2018 2017 Revolving credit facility $ — $ 188,000 Note payable 7,700 9,974 5% Senior Notes due 2022 1,598,404 1,997,576 4.5% Senior Notes due 2023 1,488,960 1,486,690 3.8% Senior Notes due 2024 993,151 992,036 4.375% Senior Notes due 2028 988,617 988,061 4.9% Senior Notes due 2044 691,517 691,354 Total debt 5,768,349 6,353,691 Less: Current portion of long-term debt 2,360 2,286 Long-term debt, net of current portion $ 5,765,989 $ 6,351,405 Revolving credit facility In April 2018, the Company entered into a new unsecured revolving credit facility, maturing in April 2023, with aggregate commitments totaling $1.5 billion , which may be increased up to a total of $4.0 billion upon agreement between the Company and participating lenders. In connection with the execution of the new credit facility, the Company terminated its then-existing $2.75 billion credit facility that was due to mature in May 2019. The Company had no outstanding borrowings on its credit facility at December 31, 2018 . Borrowings under the credit facility, if any, bear interest at market-based interest rates plus a margin based on the terms of the borrowing and the credit ratings assigned to the Company’s senior, unsecured, long-term indebtedness. The Company incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability under its credit facility. The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit 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 the credit facility covenants at December 31, 2018 . 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, 2018 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $1,600,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its remaining 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to the indicated 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 amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed 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 other things, limit the Company’s ability to create liens securing certain indebtedness, enter into certain sale-leaseback transactions, or 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, 2018 . Three of the Company’s wholly-owned subsidiaries, Banner Pipeline Company, L.L.C., CLR Asset Holdings, LLC, and The Mineral Resources Company, the value of whose assets, equity, and results of operations are minor, fully and unconditionally guarantee the senior notes on a joint and several basis. The Company’s other subsidiaries, the value of whose assets, equity, and results of operations attributable to the Company are minor, do not guarantee the senior notes. 2018 partial redemption of senior notes In August 2018, the Company redeemed $400 million , or 20% , of its previously outstanding $2.0 billion of 5% Senior Notes due 2022. The redemption price was equal to 101.667% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date in accordance with the terms of the 2022 Notes and the related indenture under which the 2022 Notes were issued. The aggregate of the principal amount, redemption premium, and accrued interest paid upon redemption of the 2022 Notes was $415.1 million . The Company recorded a pre-tax loss on extinguishment of debt related to the redemption of $7.1 million , which included the redemption premium and pro-rata write-off of deferred financing costs and unamortized debt premium associated with the notes. The loss is reflected under the caption “Loss on extinguishment of debt” in the consolidated statements of comprehensive income (loss). Note payable In February 2012, 20 Broadway Associates LLC, a wholly-owned subsidiary of the Company, borrowed $22 million under a 10 -year amortizing term loan secured by the Company’s corporate office building in Oklahoma City, Oklahoma. The loan bears interest at a fixed rate of 3.14% per annum. Principal and interest are payable monthly through the loan’s maturity date of February 26, 2022 . Accordingly, approximately $2.4 million is reflected as a current liability under the caption “Current portion of long-term debt” in the consolidated balance sheets as of December 31, 2018 .

Revenues Revenues

Revenues Revenues	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenues Adoption of new revenue recognition and disclosure guidance In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers (Topic 606) , which generally requires an entity to identify performance obligations in its contracts, estimate the amount of consideration to be received, allocate the consideration to each separate performance obligation, and recognize revenue as obligations are satisfied. Additionally, the standard requires expanded disclosures related to revenue recognition. Subsequent to the issuance of ASU 2014-09, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net), pertaining to the presentation of revenues on a gross basis (revenues presented separately from associated expenses) versus a net basis. This guidance requires an entity to record revenue on a gross basis if it controls a promised good or service before transferring it to a customer, whereas an entity records revenue on a net basis if its role is to arrange for another entity to provide the goods or services to a customer. Applying the guidance in ASU 2016-08 requires significant judgment in determining the point in time when control of products transfers to customers. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 using a modified retrospective transition approach to all applicable contracts at the date of initial application, whereby the standard has been applied for periods commencing after December 31, 2017 and prior period results have not been adjusted to conform to current presentation. Adoption of the new guidance had no cumulative effect impact on the Company's retained earnings at January 1, 2018. The new guidance does not have a material impact on the timing of the Company’s revenue recognition or its financial position, results of operations, net income, or cash flows, but does impact the Company's presentation of revenues and expenses under the gross-versus-net presentation guidance in ASU 2016-08. In years prior to 2018, the Company generally presented its revenues net of costs incurred to transport its production to market. Under the new guidance, revenues and transportation expenses associated with production originating from the Company’s operated properties are now reported on a gross basis as further discussed below. The changes from net to gross presentation resulted in an increase in revenues and a corresponding increase in separately reported transportation expenses, with no net effect on the Company’s results of operations, net income, or cash flows for the year ended December 31, 2018 . The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance. Year ended December 31, 2018 In thousands New Standard Prior Presentation Change Revenues: Crude oil and natural gas sales $ 4,678,722 $ 4,487,135 $ 191,587 Loss on natural gas derivatives, net (23,930 ) (23,930 ) — Crude oil and natural gas service operations 54,794 54,794 — Total revenues $ 4,709,586 $ 4,517,999 $ 191,587 Operating costs and expenses: Transportation expenses $ 191,587 $ — $ 191,587 Net income $ 989,700 $ 989,700 $ — Revenue from contracts with customers Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements. Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues and transportation expenses are reported on a gross basis, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $162.3 million for the year ended December 31, 2018 . Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $29.3 million for the year ended December 31, 2018 , comprised entirely of costs to transport processed residue gas. Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Revenues from derivative instruments – See Note 5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments. Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided. Disaggregation of crude oil and natural gas revenues The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the year ended December 31, 2018 . Year ended December 31, 2018 In thousands North Region South Region Total Crude oil revenues: Operated properties $ 2,330,711 $ 603,070 $ 2,933,781 Non-operated properties 790,435 68,378 858,813 Total crude oil revenues 3,121,146 671,448 3,792,594 Natural gas revenues: Operated properties 214,741 547,247 761,988 Non-operated properties 60,738 63,402 124,140 Total natural gas revenues 275,479 610,649 886,128 Crude oil and natural gas sales $ 3,396,625 $ 1,282,097 $ 4,678,722 Timing of revenue recognition Goods transferred at a point in time $ 3,396,625 $ 1,282,097 $ 4,678,722 Goods transferred over time — — — $ 3,396,625 $ 1,282,097 $ 4,678,722 Performance obligations The Company satisfies the performance obligations under its crude oil and natural gas sales contracts upon delivery of its production and related transfer of control to customers. Upon delivery of production, the Company has a right to receive consideration from its customers in amounts determined by the sales contracts. All of the Company's outstanding crude oil sales contracts at December 31, 2018 are short-term in nature with contract terms of less than one year. For such contracts, the Company has utilized the practical expedient in Accounting Standards Codification ("ASC") 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations, if any, if the performance obligation is part of a contract that has an original expected duration of one year or less. The majority of the Company's operated natural gas production is sold at lease locations to midstream customers under multi-year term contracts. For such contracts having a term greater than one year, the Company has utilized the practical expedient in ASC 606-10-50-14A which indicates an entity is not required to disclose the transaction price allocated to remaining performance obligations, if any, if variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under our sales contracts, whether for crude oil or natural gas, each unit of production delivered to a customer represents a separate performance obligation; therefore, future volumes to be delivered are wholly unsatisfied at period-end and disclosure of the transaction price allocated to remaining performance obligations is not applicable. Contract balances Under the Company’s crude oil and natural gas sales contracts or activities that give rise to service revenues, the Company recognizes revenue after its performance obligations have been satisfied, at which point the Company has an unconditional right to receive payment. Accordingly, the Company’s commodity sales contracts and service activities generally do not give rise to contract assets or contract liabilities under ASC Topic 606. Instead, the Company's unconditional rights to receive consideration are presented as a receivable within "Receivables – Crude oil and natural gas sales" or "Receivables – Joint interest and other, net", as applicable, in its consolidated balance sheets. Revenues from previously satisfied performance obligations To record revenues for commodity sales, at the end of each month the Company estimates the amount of production delivered and sold to customers and the prices to be received for such sales. Differences between estimated revenues and actual amounts received for all prior months are recorded in the month payment is received from the customer and are reflected in the financial statements within the caption "Crude oil and natural gas sales". Revenues recognized during the year ended December 31, 2018 related to performance obligations satisfied in prior reporting periods were not material.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes In December 2017, the Tax Cuts and Jobs Act was signed into law. The legislation contained several key changes to U.S. corporate tax laws, including a reduction of the corporate income tax rate from 35% to 21%, effective January 1, 2018. The legislation also included a variety of other changes such as the repeal of the alternative minimum tax; the introduction of new limitations on the tax deductibility of net operating losses, interest expenses, and executive compensation expenses; the acceleration of expensing of certain qualified property; and the introduction of new laws governing taxation of foreign earnings of U.S. entities, among others. The Company recognizes the effect of tax law changes in the reporting period that includes the enactment date in accordance with U.S. GAAP. As a result, the Company remeasured its deferred tax assets and liabilities as of December 31, 2017 to reflect the reduction in the corporate tax rate from 35% to 21% enacted into law in December 2017. This remeasurement resulted in a $713.7 million decrease in net deferred income tax liabilities and corresponding decrease in income tax expense as of and for the year ended December 31, 2017, which is reflected in the tables below. The Company's accounting for the effects of the tax rate change on its deferred tax balances as well as other relevant aspects of the Tax Cuts and Jobs Act was completed as of December 31, 2017 and no provisional amounts were recorded at that date that were later adjusted in 2018. The items comprising the Company's (provision) benefit for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2018 2017 2016 Current income tax (provision) benefit: United States federal (1) $ 7,781 $ 7,781 $ 22,941 Various states (5 ) — (2 ) Total current income tax benefit 7,776 7,781 22,939 Deferred income tax (provision) benefit: United States federal - taxation on operations (282,947 ) (81,054 ) 182,422 United States federal - effect of US tax reform — 713,655 — Various states (31,931 ) (7,002 ) 27,414 Total deferred income tax (provision) benefit (314,878 ) 625,599 209,836 (Provision) benefit for income taxes $ (307,102 ) $ 633,380 $ 232,775 (1) The current federal income tax benefits represent alternative minimum tax refunds. 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, 2018 2017 2016 In thousands, except rates Amount Rate Amount Rate Amount Rate Expected income tax (provision) benefit based on US statutory tax rate $ (272,328 ) 21.0 % $ (54,623 ) 35.0 % $ 221,359 35.0 % State income taxes, net of federal benefit (45,920 ) 3.6 % (4,682 ) 3.0 % 18,829 3.0 % Effect of US tax reform legislation — — % 713,655 (457.3 %) — — % Tax (benefit) deficiency from stock-based compensation 259 — % (3,932 ) 2.5 % — — % Non-deductible compensation (2,932 ) 0.2 % (13,813 ) 8.9 % (3,471 ) (0.5 %) Other, net 13,819 (1.1 %) (3,225 ) 2.1 % (3,942 ) (0.7 %) (Provision) benefit for income taxes $ (307,102 ) 23.7 % $ 633,380 (405.8 %) $ 232,775 36.8 % The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2018 and 2017 are reflected in the table below. December 31, In thousands 2018 2017 Deferred tax assets United States net operating loss carryforwards $ 549,166 $ 604,423 Canadian net operating loss carryforwards 19,633 19,341 Alternative minimum tax carryforwards — 7,781 Equity compensation 13,122 12,962 Other 13,622 21,885 Total deferred tax assets 595,543 666,392 Canadian valuation allowance (19,633 ) (19,341 ) Total deferred tax assets, net of valuation allowance 575,910 647,051 Deferred tax liabilities Property and equipment (2,144,767 ) (1,903,451 ) Other (5,579 ) (3,158 ) Total deferred tax liabilities (2,150,346 ) (1,906,609 ) Deferred income tax liabilities, net $ (1,574,436 ) $ (1,259,558 ) As of December 31, 2018 , the Company had federal and state net operating loss carryforwards of $1.95 billion and $3.17 billion , respectively. The federal net operating loss carryforward will begin expiring in 2035 . The Company’s net operating loss carryforward in Oklahoma totaled $2.14 billion at December 31, 2018 , which will begin to expire in 2028. The Company’s net operating loss carryforward in North Dakota totaled $898 million at December 31, 2018 , which will begin to expire in 2035. 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 or state income tax examinations by tax authorities for years prior to 2015. The Company recorded valuation allowances of $0.3 million , $0.4 million , and $1.0 million against Canadian deferred tax assets for the years ended December 31, 2018 , 2017 , and 2016 , respectively. The Company's cumulative valuation allowance was $19.6 million as of December 31, 2018 . 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 could change if our subsidiary generates taxable income.

Lease Commitments

Lease Commitments	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Lease Commitments	Lease Commitments The Company’s operating lease obligations, as defined and accounted for under legacy U.S. GAAP in effect as of December 31, 2018 , primarily represent leases for surface use agreements, office buildings and equipment, communication towers, and field equipment. Lease payments associated with operating leases for the years ended December 31, 2018 , 2017 , and 2016 were $2.0 million , $1.9 million , and $4.4 million , respectively, a portion of which was capitalized and/or billed to other interest owners. At December 31, 2018 , the minimum future rental commitments under operating leases having enforceable lease terms in excess of one year are reflected in the table below. Such commitments are reflected at undiscounted values and are not recognized on the Company's balance sheet at December 31, 2018 . In thousands Total amount 2019 $ 1,535 2020 1,042 2021 833 2022 805 2023 745 Thereafter 6,795 Total obligations $ 11,755 New lease accounting rules (ASU 2016-02) were adopted by the Company on January 1, 2019 that require enforceable long-term commitments under certain contracts which contain leases, as defined in ASU 2016-02, to be recognized on the Company's balance sheet at discounted present value. See Note 1. Organization and Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2018–Leases for further discussion.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2018
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, 2018 . The commitments under these arrangements are not recorded in the accompanying consolidated balance sheets at December 31, 2018 . Drilling commitments – As of December 31, 2018 , the Company has drilling rig contracts with various terms extending to February 2020 to ensure rig availability in its key operating areas. Future operating day-rate commitments as of December 31, 2018 total approximately $107 million , of which $106 million is expected to be incurred in 2019 and $1 million in 2020. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations to be incurred in 2019 and 2020 at a discounted present value totaling $13 million that qualify as leases and were recognized on the Company's balance sheet on January 1, 2019 upon adoption of ASU 2016-02 as discussed in Note 1. Organization and Summary of Significant Accounting Policies–New accounting pronouncements not yet adopted at December 31, 2018–Leases . Transportation and processing commitments – The Company has entered into transportation and processing commitments to guarantee capacity on crude oil and natural gas pipelines and natural gas processing facilities. The commitments, which have varying terms extending as far as 2028, require the Company to pay per-unit transportation or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2018 under the arrangements amount to approximately $1.83 billion , of which $241 million is expected to be incurred in 2019, $273 million in 2020, $254 million in 2021, $249 million in 2022, $248 million in 2023, and $566 million thereafter. A portion of these future costs will be borne by other interest owners. The Company is not committed under the above contracts to deliver fixed and determinable quantities of crude oil or natural gas in the future. These commitments do not qualify as leases to be recognized on the balance sheet under ASU 2016-02 beginning January 1, 2019. 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, as amended, 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 sought recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the proposed class. The Company denied all allegations and denied that the case was properly brought as a class action. On June 11, 2015, the trial court certified a “hybrid” class requested by plaintiffs over the objections of the Company. The Company appealed the trial court’s class certification order. On February 8, 2017, the Oklahoma Court of Civil Appeals reversed the trial court’s ruling on certification and remanded the case for further proceedings. After certification of the case as a class action was reversed the parties engaged in settlement negotiations. Due to the uncertainty of and burdens of litigation, on February 16, 2018 the Company reached a settlement in connection with this matter. Under the settlement, the Company initially expected to make payments and incur costs associated with the settlement of approximately $59.6 million and accrued a loss for such amount at December 31, 2017. On April 3, 2018, the District Court of Garfield County, Oklahoma preliminarily approved the settlement and set certain dates applicable to the settlement including the timing and content of Notice, Opt-out, and Objections to Class Members. On June 12, 2018, the court entered an order formally approving the settlement, which is not subject to appeal. In the third quarter of 2018, the Company made payments totaling $45.8 million to satisfy the majority of its obligations under the settlement. The Company's remaining loss accrual for this matter totals $19.8 million at December 31, 2018 , representing additional settlement obligations expected to be satisfied in 2019. The accrual for this matter is included in “Accrued liabilities and other” on the consolidated balance sheets. 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, regulatory compliance matters, 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. In addition to the accrued loss on the matter described above, as of December 31, 2018 and 2017 the Company had recorded a liability in the consolidated balance sheets under the caption “Other noncurrent liabilities” of $4.7 million and $7.6 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, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions 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 $0.5 million , $0.5 million , and $0.4 million and received payments from these affiliates of $0.2 million , $0.3 million , and $0.3 million during the years ended December 31, 2018 , 2017 , and 2016 , respectively, relating to the operations of the respective properties. At December 31, 2018 and 2017 , approximately $67,000 and $58,000 was due from these affiliates, respectively, and approximately $41,000 and $48,000 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 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. In 2016, the Company also purchased an existing prepaid maintenance account from an affiliate for use in major engine overhaul to be applied as needed for corporate aircrafts. For usage during 2018 , 2017 , and 2016 , the Company charged affiliates approximately $12,900 , $19,400 , and $9,500 , respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $14,400 , $18,600 , and $6,800 from affiliates in 2018 , 2017 , and 2016 , respectively. The Company was charged approximately $598,000 , $460,000 , and $292,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2018 , 2017 , and 2016 (including the aforementioned prepayment) and paid $529,000 , $368,000 , and $195,000 to the affiliates in 2018 , 2017 , and 2016 , respectively. At December 31, 2018 and 2017 , approximately $2,700 and $4,200 was due from an affiliate, respectively, and approximately $161,000 and $92,000 was due to an affiliate, respectively, relating to these transactions. The Company capitalized costs of $0.1 million in 2016 associated with drilling rig services and demobilization of a drilling rig provided by an affiliate. The total amount paid to the affiliate, a portion of which was billed to other interest owners, was $0.1 million for the year ended December 31, 2016 . No amounts were due to the affiliate at December 31, 2018 and 2017 related to the services.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2018
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. 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 $47.2 million , $45.9 million , and $48.1 million for the years ended December 31, 2018 , 2017 and 2016 , respectively. In May 2013, the Company adopted the 2013 Plan and reserved 19,680,072 shares of common stock that may be issued pursuant to the plan. As of December 31, 2018 , the Company had 13,736,734 shares of common stock available for long-term incentive awards to employees and directors under the 2013 Plan. Restricted stock is awarded in the name of the recipient and constitutes issued and outstanding shares of the Company’s common stock for all corporate purposes during the period of restriction and, except as otherwise provided under the 2013 Plan or agreement relevant to a given award, includes the right to vote the restricted stock and 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, 2015 to December 31, 2018 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 Granted 2,064,508 22.36 Vested (1,207,235 ) 41.27 Forfeited (193,250 ) 39.79 Non-vested restricted shares at December 31, 2016 3,913,634 $ 37.12 Granted 1,585,870 44.58 Vested (874,665 ) 57.36 Forfeited (598,729 ) 37.34 Non-vested restricted shares at December 31, 2017 4,026,110 $ 35.63 Granted 1,390,914 52.71 Vested (1,116,329 ) 46.19 Forfeited (278,286 ) 38.06 Non-vested restricted shares at December 31, 2018 4,022,409 $ 38.44 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 determined at the grant date fair value and is recognized over the vesting period as services are rendered by employees and directors. The Company estimates the number of forfeitures expected to occur in determining the amount of stock-based compensation expense to recognize. 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 2018 , 2017 and 2016 was approximately $61.0 million , $39.8 million and $30.0 million , respectively. As of December 31, 2018 , there was approximately $70 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.0 year.

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income Accumulated Other Comprehensive Income (Loss) (Notes)	12 Months Ended
	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Comprehensive Income (Loss) Note [Text Block]	Accumulated Other Comprehensive Income (Loss) Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income (loss)” within shareholders’ equity attributable to Continental Resources on the consolidated balance sheets and “Other comprehensive income, net of tax” in the consolidated statements of comprehensive income (loss). The following table summarizes the change in accumulated other comprehensive income (loss) for the years ended December 31, 2018 , 2017 , and 2016 : Year ended December 31, In thousands 2018 2017 2016 Beginning accumulated other comprehensive income (loss), net of tax $ 307 $ (260 ) $ (3,354 ) Foreign currency translation adjustments 108 567 3,094 Income taxes (1) — — — Other comprehensive income, net of tax 108 567 3,094 Ending accumulated other comprehensive income (loss), net of tax $ 415 $ 307 $ (260 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Noncontrolling Interests Noncon

Noncontrolling Interests Noncontrolling Interests	12 Months Ended
	Dec. 31, 2018
Noncontrolling Interest [Abstract]
Noncontrolling Interest Disclosure [Text Block]	Noncontrolling Interests Strategic mineral relationship In October 2018, Continental entered into a strategic relationship with Franco-Nevada Corporation to acquire oil and gas mineral interests in the SCOOP and STACK plays through a newly-formed minerals subsidiary named The Mineral Resources Company II, LLC ("TMRC II"). At closing, Continental contributed most of its previously acquired mineral interests to TMRC II in exchange for a 50.1% ownership interest in the entity. Additionally, at closing Franco-Nevada paid $214.8 million to Continental for a 49.9% ownership interest in TMRC II and for funding of its share of certain mineral acquisition costs. In accordance with the transaction terms, the parties have committed, subject to satisfaction of agreed upon acreage development thresholds, to spend a remaining aggregate total of approximately $309 million through year-end 2021 to acquire additional oil and gas mineral interests through TMRC II. Continental is to fund 20% of future mineral acquisitions and will be entitled to receive between 25% and 50% of total revenues generated by TMRC II based upon performance relative to certain predetermined production targets. Continental holds a controlling financial interest in TMRC II. Accordingly, Continental has consolidated the financial results of the entity and has presented the portion of TMRC II's results attributable to Franco-Nevada as a noncontrolling interest in its consolidated financial statements. Subsequent to closing, Franco-Nevada made additional capital contributions to, and received revenue distributions from, TMRC II in 2018 and the portion of Continental's consolidated net assets attributable to Franco-Nevada totaled $266.8 million at December 31, 2018 . Continental incurred $4.8 million of costs associated with this transaction, which were recognized as a reduction of "Additional paid-in capital" within shareholders’ equity attributable to Continental. Joint ownership arrangement In December 2018, Continental entered into an arrangement with a third party to jointly acquire parking facilities adjacent to the companies' corporate office buildings. The activities of the parking facilities, which are immaterial to Continental, are managed through a newly-formed entity named SFPG, LLC. Continental holds a 57.4% controlling financial interest in SFPG and, accordingly, has consolidated the financial results of the entity and has included the results attributable to the third party within noncontrolling interests in Continental's financial statements. The portion of Continental's consolidated net assets attributable to the third party's ownership interest in SFPG totaled $9.9 million at December 31, 2018 .

Property Dispositions

Property Dispositions	12 Months Ended
	Dec. 31, 2018
Extractive Industries [Abstract]
Property Dispositions	Property Dispositions 2018 During 2018 , the Company sold non-strategic properties in various areas for cash proceeds totaling $54.5 million . The Company recognized pre-tax gains on the transactions totaling $16.7 million . The disposed properties represented an immaterial portion of the Company’s production and proved reserves. 2017 In October 2017, the Company sold non-core leasehold in the STACK play for cash proceeds totaling $63.5 million and recognized a $56.9 million pre-tax gain in 2017 associated with the transaction. The disposed properties represented an immaterial portion of the Company’s production and proved reserves. In September 2017, the Company sold properties in the Arkoma Woodford area for cash proceeds of $65.3 million . The sale included approximately 26,000 net acres of leasehold and producing properties with production totaling approximately 1,700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax loss of $3.5 million in 2017. The disposed properties represented an immaterial portion of the Company’s proved reserves. In September 2017, the Company sold certain oil-loading facilities in Oklahoma for $7.2 million and recognized a $4.2 million pre-tax gain in 2017 associated with the transaction. 2016 In October 2016, the Company sold approximately 30,000 net acres of non-core leasehold in the SCOOP play for cash proceeds totaling $295.6 million . The leasehold included producing properties with production totaling approximately 700 barrels of oil equivalent per day. In connection with the transaction, the Company recognized a pre-tax gain of $201.0 million . The disposed properties represented an immaterial portion of the Company’s proved reserves. In September 2016, the Company sold properties in North Dakota and Montana for cash proceeds totaling $214.8 million , with no gain or loss recognized. The sale included approximately 68,000 net acres of leasehold in North Dakota and approximately 12,000 net acres of leasehold in Montana. The sale also included producing properties with production totaling approximately 2,700 barrels of oil equivalent per day. The disposed properties represented an immaterial portion of the Company’s proved reserves. In April 2016, the Company sold approximately 132,000 net acres of undeveloped leasehold in Wyoming for cash proceeds totaling $110.0 million . In connection with the transaction, the Company recognized a pre-tax gain of $96.9 million . The disposed properties had no production or proved reserves.

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2018
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, 2018, 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. Additionally, results attributable to noncontrolling interests are immaterial and are not separately presented 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, 2018 , 2017 and 2016 . Year ended December 31, In thousands 2018 2017 2016 Crude oil and natural gas sales (1) $ 4,678,722 $ 2,982,966 $ 2,026,958 Production expenses (390,423 ) (324,214 ) (289,289 ) Production taxes (353,140 ) (208,278 ) (142,388 ) Transportation expenses (1) (191,587 ) — — Exploration expenses (7,642 ) (12,393 ) (16,972 ) Depreciation, depletion, amortization and accretion (1,839,241 ) (1,652,180 ) (1,679,485 ) Property impairments (125,210 ) (237,370 ) (237,292 ) Income tax (provision) benefit (2) (434,047 ) 504,475 126,794 Results from crude oil and natural gas producing activities $ 1,337,432 $ 1,053,006 $ (211,674 ) (1) For 2018, crude oil and natural gas sales are presented gross of certain transportation expenses as a result of the Company's January 1, 2018 adoption of new revenue recognition and presentation rules as discussed in Note 8. Revenues. The new rules were prospectively applied beginning January 1, 2018 and prior period results have not been adjusted to conform to the current presentation. (2) Income taxes reflect the application of a combined federal and state tax rate of 24.5% for 2018 and 38% for both 2017 and 2016 on pre-tax income and losses generated by operations in the United States. Additionally, the 2017 period includes a $713.7 million income tax benefit recognized upon the Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 9. Income Taxes for further discussion. 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, 2018 , 2017 and 2016 are presented below: Year ended December 31, In thousands 2018 2017 2016 Property acquisition costs: Proved $ 31,579 $ 8,446 $ 5,008 Unproved 329,586 220,875 149,962 Total property acquisition costs 361,165 229,321 154,970 Exploration Costs 81,015 123,461 182,355 Development Costs 2,478,327 1,695,954 767,148 Total $ 2,920,507 $ 2,048,736 $ 1,104,473 Costs incurred above include asset retirement costs and revisions thereto of $25.8 million , $15.3 million and ($9.6) million for the years ended December 31, 2018 , 2017 and 2016 , 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, 2018 and 2017 are as follows: December 31, In thousands 2018 2017 Proved crude oil and natural gas properties $ 24,060,625 $ 21,362,199 Unproved crude oil and natural gas properties 291,564 365,413 Total 24,352,189 21,727,612 Less accumulated depreciation, depletion and amortization (10,680,870 ) (8,971,935 ) Net capitalized costs $ 13,671,319 $ 12,755,677 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 and completion 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 at least 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 well 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 2018 2017 2016 Balance at January 1 $ 31,356 $ 34,852 $ 59,397 Additions to capitalized exploratory well costs pending determination of proved reserves 45,088 79,451 123,980 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (72,347 ) (81,035 ) (141,941 ) Capitalized exploratory well costs charged to expense (138 ) (1,912 ) (6,584 ) Balance at December 31 $ 3,959 $ 31,356 $ 34,852 Number of gross wells 16 37 54 As of December 31, 2018 , the Company had no significant exploratory well costs that were suspended one year beyond the completion of drilling.

Supplemental Crude Oil and Natu

Supplemental Crude Oil and Natural Gas Information (Unaudited)	12 Months Ended
	Dec. 31, 2018
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. prepared reserve estimates for properties comprising approximately 98% , 96% , and 99% of the Company's total proved reserves as of December 31, 2018 , 2017 , and 2016 , respectively. 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 included for the Company’s Canadian operations as of December 31, 2018 , 2017 , and 2016 . Proved reserves attributable to noncontrolling interests are immaterial and are not separately presented in the tables below. 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 or removals of 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, changes in business strategies, 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, 2018 , 2017 and 2016 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, 2018 , 2017 and 2016 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, 2015 700,514 3,151,786 1,225,811 Revisions of previous estimates (99,966 ) (63,057 ) (110,474 ) Extensions, discoveries and other additions 97,587 911,062 249,430 Production (46,850 ) (195,240 ) (79,390 ) Sales of minerals in place (8,057 ) (14,733 ) (10,513 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2016 643,228 3,789,818 1,274,864 Revisions of previous estimates (77,779 ) (25,390 ) (82,012 ) Extensions, discoveries and other additions 129,895 661,867 240,206 Production (50,536 ) (228,159 ) (88,562 ) Sales of minerals in place (4,365 ) (64,989 ) (15,197 ) Purchases of minerals in place 506 7,134 1,696 Proved reserves as of December 31, 2017 640,949 4,140,281 1,330,995 Revisions of previous estimates (76,994 ) (1,153,555 ) (269,253 ) Extensions, discoveries and other additions 253,066 1,871,777 565,030 Production (61,384 ) (284,730 ) (108,839 ) Sales of minerals in place (2,154 ) (35,142 ) (8,011 ) Purchases of minerals in place 3,613 52,983 12,443 Proved reserves as of December 31, 2018 757,096 4,591,614 1,522,365 Revisions of previous estimates. Revisions for 2018 are comprised of (i) the removal of 74 MMBo and 960 Bcf (totaling 234 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to the continual refinement of the Company's drilling programs and reallocation of capital to areas providing the greatest opportunities to improve efficiencies, recoveries, and rates of return, (ii) downward revisions of 21 MMBo and 216 Bcf (totaling 57 MMBoe) from the removal of PUD reserves due to changes in anticipated well densities and other factors, (iii) upward price revisions of 21 MMBo and 31 Bcf (totaling 26 MMBoe) due to an increase in average crude oil and natural gas prices in 2018 compared to 2017, and (iv) net downward revisions of 2 MMBo and 11 Bcf (totaling 4 MMBoe) due to changes in ownership interests, operating costs, anticipated production performance, and other factors. Revisions for 2017 are comprised of (i) the removal of 89 MMBoe of PUD reserves not scheduled to be drilled within five years of initial booking due to changes in development plans, (ii) upward price revisions of 42 MMBoe due to an increase in average crude oil and natural gas prices in 2017 compared to 2016, (iii) downward revisions of 30 MMBoe due to changes in anticipated production performance, and (iv) net downward revisions of 5 MMBoe due to changes in ownership interests, operating costs, and other factors. Revisions for 2016 are comprised of (i) the removal of 70 MMBoe of PUD reserves not scheduled to be drilled within five years of initial booking due to changes in development plans, (ii) downward price revisions of 28 MMBoe due to a decrease in average crude oil and natural gas prices in 2016 compared to 2015, and (iii) net downward revisions of 12 MMBoe due to changes in ownership interests, operating costs, anticipated production performance, and other factors. Extensions, discoveries and other additions . Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs in the Bakken, SCOOP, and STACK plays. For 2018, proved reserve additions in the Bakken totaled 176 MMBo and 448 Bcf (totaling 251 MMBoe) and reserve additions in SCOOP totaled 64 MMBo and 733 Bcf (totaling 186 MMBoe). Additionally, 2018 proved reserve additions in STACK totaled 13 MMBo and 691 Bcf (totaling 128 MMBoe). Sales of minerals in place. See Note 16. Property Dispositions for a discussion of notable dispositions in 2016, 2017, and 2018, none of which involved significant volumes of proved reserves. Purchases of minerals in place. There were no individually significant acquisitions of proved reserves in the three years reflected in the table above. The increase in acquired reserves in 2018 compared to prior years was due to higher mineral acquisition spending. 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, 2018 , 2017 and 2016 : December 31, 2018 2017 2016 Proved Developed Reserves Crude oil (MBbl) 347,825 318,707 290,210 Natural Gas (MMcf) 1,964,289 1,699,161 1,370,620 Total (MBoe) 675,206 601,901 518,646 Proved Undeveloped Reserves Crude oil (MBbl) 409,271 322,242 353,018 Natural Gas (MMcf) 2,627,325 2,441,120 2,419,198 Total (MBoe) 847,159 729,094 756,218 Total Proved Reserves Crude oil (MBbl) 757,096 640,949 643,228 Natural Gas (MMcf) 4,591,614 4,140,281 3,789,818 Total (MBoe) 1,522,365 1,330,995 1,274,864 Proved developed reserves are reserves expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are reserves expected to be recovered from new wells on undrilled acreage or from existing wells that require relatively major capital expenditures to recover, including most wells where drilling has occurred but the wells have not been completed. 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 proved crude oil and natural gas reserves as of December 31, 2018 , 2017 and 2016 . Discounted future net cash flows attributable to noncontrolling interests are immaterial and are not separately presented below. December 31, In thousands 2018 2017 2016 Future cash inflows $ 61,510,432 $ 42,574,897 $ 31,008,587 Future production costs (16,139,001 ) (11,159,362 ) (9,175,410 ) Future development and abandonment costs (9,706,114 ) (6,487,097 ) (6,452,647 ) Future income taxes (1) (6,012,439 ) (3,488,755 ) (3,018,839 ) Future net cash flows 29,652,878 21,439,683 12,361,691 10% annual discount for estimated timing of cash flows (13,968,061 ) (10,969,506 ) (6,851,468 ) Standardized measure of discounted future net cash flows $ 15,684,817 $ 10,470,177 $ 5,510,223 (1) Estimated future income taxes were calculated by applying existing statutory tax rates, including any known future changes, to the estimated pre-tax net cash flows related to proved crude oil and natural gas reserves, giving effect to any permanent taxable differences and tax credits, less the tax basis of the properties involved. The U.S. federal statutory tax rate utilized in estimating future income taxes was 21% at December 31, 2018 and 2017 and 35% at December 31, 2016. The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $61.20 , $47.03 , and $35.57 per barrel at December 31, 2018 , 2017 and 2016 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $3.22 , $3.00 , and $2.14 per Mcf at December 31, 2018 , 2017 and 2016 , 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 proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2018 2017 2016 Standardized measure of discounted future net cash flows at January 1 $ 10,470,177 $ 5,510,223 $ 6,476,284 Extensions, discoveries and improved recoveries, less related costs 5,162,635 1,462,629 786,587 Revisions of previous quantity estimates (3,522,428 ) (1,004,355 ) (794,785 ) Changes in estimated future development and abandonment costs 1,063,089 743,657 1,651,218 Sales of minerals in place, net (9,192 ) (41,077 ) (90,390 ) Net change in prices and production costs 4,224,473 3,808,116 (2,003,163 ) Accretion of discount 1,183,347 665,507 798,597 Sales of crude oil and natural gas produced, net of production costs (3,743,572 ) (2,450,474 ) (1,595,281 ) Development costs incurred during the period 1,134,153 1,045,875 454,983 Change in timing of estimated future production and other 1,324,365 948,519 (538,665 ) Change in income taxes (1,602,230 ) (218,443 ) 364,838 Net change 5,214,640 4,959,954 (966,061 ) Standardized measure of discounted future net cash flows at December 31 $ 15,684,817 $ 10,470,177 $ 5,510,223

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2018 Total revenues (1) $ 1,141,028 $ 1,137,113 $ 1,282,151 $ 1,149,294 Gain (loss) on natural gas derivatives, net (1) $ 10,174 $ (12,685 ) $ (2,025 ) $ (19,394 ) Property impairments (2) $ 33,784 $ 29,162 $ 23,770 $ 38,494 Gain on sale of assets, net (3) $ 41 $ 6,710 $ 1,510 $ 8,410 Income from operations $ 380,722 $ 391,276 $ 491,308 $ 330,414 Loss on extinguishment of debt (4) $ — $ — $ (7,133 ) $ — Net income $ 233,946 $ 242,464 $ 314,169 $ 199,121 Net income attributable to Continental Resources $ 233,946 $ 242,464 $ 314,169 $ 197,738 Net income per share attributable to Continental Resources: Basic $ 0.63 $ 0.65 $ 0.84 $ 0.53 Diluted $ 0.63 $ 0.65 $ 0.84 $ 0.53 2017 Total revenues (1) $ 685,427 $ 661,486 $ 726,743 $ 1,047,172 Gain on natural gas derivatives, net (1) $ 46,858 $ 28,022 $ 8,602 $ 8,165 Property impairments (2) $ 51,372 $ 123,316 $ 35,130 $ 27,552 Litigation settlement (5) $ — $ — $ — $ 59,600 Gain (loss) on sale of assets, net (3) $ (3,638 ) $ 780 $ 3,562 $ 54,420 Income (loss) from operations $ 77,221 $ (29,041 ) $ 91,753 $ 309,468 Net income (loss) (6) $ 469 $ (63,557 ) $ 10,621 $ 841,914 Net income (loss) per share: Basic $ — $ (0.17 ) $ 0.03 $ 2.27 Diluted $ — $ (0.17 ) $ 0.03 $ 2.25 (1) Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Natural gas 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. Additionally, beginning in 2018 certain transportation expenses are no longer netted within "Total revenues" as a result of the Company's January 1, 2018 prospective adoption of ASU 2016-08, which affects comparability of 2017 and 2018 revenues. Transportation expenses totaled $49.3 million , $47.3 million , $46.0 million , and $49.0 million for the first, second, third, and fourth quarters of 2018, respectively. (2) Property impairments have been shown separately to illustrate the impact on quarterly results 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) Gains and losses on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 16. Property Dispositions for a discussion of notable dispositions. (4) See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the partial redemption of its 2022 Notes in the 2018 third quarter. (5) Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies—Litigation , which resulted in an after-tax decrease in net income of $37.0 million ( $0.10 per basic and diluted share). (6) Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share). See Note 9. Income Taxes for further discussion.

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2018
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. Additionally, the Company pursues the acquisition and management of perpetually owned minerals located in certain of its key operating areas. 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 Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
Basis of presentation of consolidated financial statements	Basis of presentation of consolidated financial statements The consolidated financial statements include the accounts of the Company, its wholly-owned subsidiaries, and entities in which the Company has a controlling financial interest. Intercompany accounts and transactions have been eliminated upon consolidation. Noncontrolling interests reflected herein represent third party ownership in the net assets of consolidated subsidiaries. The portions of consolidated net income and equity attributable to the noncontrolling interests are presented separately in the Company’s financial statements.
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 periods. Actual results may differ from those estimates. The most significant estimates and assumptions impacting reported results are 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	Below is a discussion of the nature, timing, and presentation of revenues arising from the Company's major revenue-generating arrangements. Operated crude oil revenues – The Company pays third parties to transport the majority of its operated crude oil production from lease locations to downstream market centers, at which time the Company's customers take title and custody of the product in exchange for prices based on the particular market where the product was delivered. Operated crude oil revenues are recognized during the month in which control transfers to the customer and it is probable the Company will collect the consideration it is entitled to receive. Crude oil sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Operated crude oil revenues and transportation expenses are reported on a gross basis, as the Company controls the operated production prior to its transfer to customers. Transportation expenses associated with the Company's operated crude oil production totaled $162.3 million for the year ended December 31, 2018 . Operated natural gas revenues – The Company sells the majority of its operated natural gas production to midstream customers at its lease locations based on market prices in the field where the sales occur. Under these arrangements, the midstream customers obtain control of the unprocessed gas stream at the lease location and the Company's revenues from each sale are determined using contractually agreed pricing formulas which contain multiple components, including the volume and Btu content of the natural gas sold, the midstream customer's proceeds from the sale of residue gas and natural gas liquids ("NGLs") at secondary downstream markets, and contractual pricing adjustments reflecting the midstream customer's estimated recoupment of its investment over time. Such revenues are recognized net of pricing adjustments applied by the midstream customer during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Natural gas sales proceeds from operated properties are generally received by the Company within one month after the month in which a sale has occurred. Under certain arrangements, the Company has the right to take a volume of processed residue gas and/or NGLs in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of the Company's operated natural gas production. When the Company elects to take volumes in kind, it pays third parties to transport the processed products it took in-kind to downstream delivery points, where it then sells to customers at prices applicable to those downstream markets. In such situations, operated revenues are recognized during the month in which control transfers to the customer at the delivery point and it is probable the Company will collect the consideration it is entitled to receive. Operated sales proceeds are generally received by the Company within one month after the month in which a sale has occurred. In these scenarios, the Company's revenues include the pricing adjustments applied by the midstream processing entity according to the applicable contractual pricing formula, but exclude the transportation expenses the Company incurs to transport the processed products to downstream customers. Transportation expenses associated with these arrangements totaled $29.3 million for the year ended December 31, 2018 , comprised entirely of costs to transport processed residue gas. Non-operated crude oil and natural gas revenues – The Company's proportionate share of production from non-operated properties is generally marketed at the discretion of the operators. For non-operated properties, the Company receives a net payment from the operator representing its proportionate share of sales proceeds which is net of costs incurred by the operator, if any. Such non-operated revenues are recognized at the net amount of proceeds to be received by the Company during the month in which production occurs and it is probable the Company will collect the consideration it is entitled to receive. Proceeds are generally received by the Company within two to three months after the month in which production occurs. Revenues from derivative instruments – See Note 5. Derivative Instruments for discussion of the Company's accounting for its derivative instruments. Revenues from service operations – Revenues from the Company's crude oil and natural gas service operations consist primarily of revenues associated with water gathering, recycling, and disposal activities and the treatment and sale of crude oil reclaimed from waste products. Revenues associated with such activities, which are derived using market-based rates or rates commensurate with industry guidelines, are recognized during the month in which services are performed, the Company has an unconditional right to receive payment, and collectability is probable. Payment is generally received by the Company within one month after the month in which services are provided.
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, 2018 , the Company had cash deposits in excess of federally insured amounts of approximately $280.7 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 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. The Company’s allowance for doubtful accounts totaled $2.4 million and $2.2 million as of December 31, 2018 and 2017 , respectively, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets.
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 significant purchasers. For the year ended December 31, 2018 , sales to the Company’s largest purchaser accounted for approximately 12% of the Company’s total crude oil and natural gas sales. No other purchaser accounted for more than 10% of the Company’s total crude oil and natural gas sales for 2018 . The Company generally 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, pipeline imbalances, 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 net realizable value primarily using the first-in, first-out inventory method. Tubular goods and equipment are valued primarily using a weighted average cost method applied to specific classes of inventory items. The components of inventory as of December 31, 2018 and 2017 consisted of the following: December 31, In thousands 2018 2017 Tubular goods and equipment $ 14,623 $ 14,946 Crude oil 73,921 82,460 Total $ 88,544 $ 97,406
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. 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 but are not limited to labor costs to operate the Company’s properties, repairs and maintenance, certain waste water disposal costs, utility costs, certain workover-related 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 and recycling 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 and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40
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. The Company’s primary asset retirement obligations relate to future plugging and abandonment costs and related disposal of facilities on its crude oil and natural gas properties.
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. Impairment losses for unproved properties are generally 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 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). Gains and losses on crude oil and natural gas derivatives are reflected in the caption “ Gain (loss) on crude oil and natural gas derivatives, net .” Gains and losses on diesel fuel derivatives are reflected in the caption “Operating costs and expenses—Net gain on sale of assets and other.”
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, 2018 and 2017 .
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. The Company recorded valuation allowances of $0.3 million , $0.4 million , and $1.0 million for the years ended December 31, 2018 , 2017 , and 2016 , 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	Earnings per share attributable to Continental Resources Basic net income (loss) per share is computed by dividing net income (loss) attributable to the Company by the weighted-average number of shares outstanding for the period. In periods where the Company has net income, diluted earnings 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	Foreign currency translation In 2014, the Company initiated exploratory drilling activities in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada are immaterial. 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 income” within equity on the consolidated balance sheets and “Other comprehensive income, net of tax” in the consolidated statements of comprehensive income (loss).
New Accounting Pronouncements	Adoption of new accounting pronouncements in 2018 Revenue recognition and presentation – In May 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2014-09, Revenue from Contracts with Customers (Topic 606) , which superseded nearly all previously existing revenue recognition guidance under U.S. GAAP. Subsequently, the FASB issued additional guidance to assist entities with implementation efforts, including the issuance of ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This new guidance became effective for reporting periods beginning after December 15, 2017. The Company adopted the new revenue recognition and presentation guidance on January 1, 2018 as required. See Note 8. Revenues for discussion of the adoption impact and the applicable disclosures required by the new guidance. New accounting pronouncements not yet adopted at December 31, 2018 Leases – In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) , which requires companies to recognize a right of use asset and related liability on the balance sheet for the rights and obligations arising from leases with durations greater than 12 months. The standard became effective for interim and annual reporting periods beginning after December 15, 2018. The Company adopted the new standard on January 1, 2019 on a prospective basis using the simplified transition method prescribed by ASU 2018-11, Leases (Topic 842): Targeted Improvements. Offsetting lease assets and lease liabilities recognized by the Company on the adoption date totaled approximately $19 million , representing minimum payment obligations associated with drilling rig commitments, surface use agreements, equipment, and other leases with contractual durations in excess of one year. Such leases, all of which are operating leases, had a weighted average remaining life and discount rate of 5.4 years and 4.5% , respectively, as of January 1, 2019. The Company has elected to account for lease and non-lease components in its contracts as a single lease component for all asset classes. Additionally, the Company has elected not to apply the recognition requirements of ASU 2016-02 to leases with durations of twelve months or less. No cumulative-effect adjustment to retained earnings was recognized upon adoption of the new lease standard. The value of lease assets and lease liabilities recognized under ASU 2016-02 will change with the passage of time and from changes in the nature, timing, and extent of the Company's contractual lease arrangements in effect from period to period. As a result, the lease assets and liabilities recognized by the Company as of January 1, 2019 may not be indicative of amounts to be recognized in future periods. The Company continues to work on finalizing its implementation of procedures to comply with the new disclosure requirements prescribed by ASU 2016-02. Credit losses – In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace the currently required incurred loss approach with an expected loss model for instruments measured at amortized cost. The standard is effective for interim and annual periods beginning after December 15, 2019 and shall be applied using a modified retrospective approach resulting in a cumulative effect adjustment to retained earnings upon adoption. The Company continues to evaluate the new standard and is unable to estimate its financial statement impact at this time; however, the impact is not expected to be material. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2018 and 2017 consisted of the following: December 31, In thousands 2018 2017 Tubular goods and equipment $ 14,623 $ 14,946 Crude oil 73,921 82,460 Total $ 88,544 $ 97,406
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 and recycling systems 15-30 Storage tanks 10-30 Office and computer equipment, software, furniture and fixtures 3-25 Buildings and improvements 4-40
Summary of Changes in Future Abandonment Liabilities	The following table summarizes the changes in the Company’s future abandonment liabilities from January 1, 2016 through December 31, 2018 : In thousands 2018 2017 2016 Asset retirement obligations at January 1 $ 114,406 $ 96,178 $ 102,909 Accretion expense 6,985 5,886 6,086 Revisions (1) 13,075 7,801 (12,755 ) Plus: Additions for new assets 9,070 6,884 2,692 Less: Plugging costs and sold assets (2,176 ) (2,343 ) (2,754 ) Total asset retirement obligations at December 31 $ 141,360 $ 114,406 $ 96,178 Less: Current portion of asset retirement obligations at December 31 (2) 4,374 2,612 1,742 Non-current portion of asset retirement obligations at December 31 $ 136,986 $ 111,794 $ 94,436 (1) Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of 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	The following table presents the calculation of basic and diluted weighted average shares outstanding and net income (loss) per share attributable to the Company for the years ended December 31, 2018 , 2017 and 2016 . Year ended December 31, In thousands, except per share data 2018 2017 2016 Net income (loss) attributable to Continental Resources (numerator) (1) $ 988,317 $ 789,447 $ (399,679 ) Weighted average shares (denominator): Weighted average shares - basic 371,854 371,066 370,380 Non-vested restricted stock (2) 2,984 2,702 — Weighted average shares - diluted 374,838 373,768 370,380 Net income (loss) per share attributable to Continental Resources: (1) Basic $ 2.66 $ 2.13 $ (1.08 ) Diluted $ 2.64 $ 2.11 $ (1.08 ) (1) The Company remeasured its deferred income tax assets and liabilities at year-end 2017 in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of $713.7 million ( $1.92 per basic share and $1.91 per diluted share) for 2017. See Note 9. Income Taxes for further discussion. Additionally, 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies—Litigation , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share). (2) For the year ended December 31, 2016, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2016 Supplemental cash flow information: Cash paid for interest $ 270,927 $ 281,058 $ 316,116 Cash paid for income taxes — 2 2 Cash received for income tax refunds 7,893 257 174 Non-cash investing activities: Asset retirement obligation additions and revisions, net 22,145 14,685 (10,063 )

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2018 and 2017 . December 31, In thousands 2018 2017 Proved crude oil and natural gas properties $ 24,060,625 $ 21,362,199 Unproved crude oil and natural gas properties 291,564 365,413 Service properties, equipment and other 324,758 290,111 Total property and equipment 24,676,947 22,017,723 Accumulated depreciation, depletion and amortization (10,807,147 ) (9,083,934 ) Net property and equipment $ 13,869,800 $ 12,933,789

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2018
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2018 and 2017 : December 31, In thousands 2018 2017 Prepaid advances from joint interest owners $ 53,674 $ 34,511 Accrued compensation 69,338 65,308 Accrued production taxes, ad valorem taxes and other non-income taxes 52,105 40,611 Accrued interest 64,483 55,282 Accrued litigation settlement (see Note 11) 19,753 59,600 Current portion of asset retirement obligations 4,374 2,612 Other 3,092 2,150 Accrued liabilities and other $ 266,819 $ 260,074

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2018
Derivative [Line Items]
Summary of Outstanding Contracts with Respect to Natural Gas	Floors Ceilings Period and Type of Contract MMBtus Swaps Weighted Average Price Range Weighted average price Range Weighted average price January 2019 - March 2019 Swaps - Henry Hub 4,950,000 $ 4.70 April 2019 - December 2019 Swaps - Henry Hub 95,425,000 $ 2.78 January 2019 - March 2019 Collars - Henry Hub 4,950,000 $ 4.25 $ 4.25 $5.50 - $5.58 $ 5.52
Realized and Unrealized Gains and Losses on Derivative Instruments	Cash receipts in the following table reflect gains on diesel fuel derivatives which matured during the respective 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 diesel fuel derivatives held at period end, if any, and the reversal of previously recognized non-cash gains or losses on derivative contracts that matured during the respective period. Year ended December 31, In thousands 2017 2016 Cash received on diesel fuel derivatives $ 2,845 $ 699 Non-cash gain (loss) on diesel fuel derivatives (4,060 ) 4,060 Gain (loss) on diesel fuel derivatives, net $ (1,215 ) $ 4,759 Year ended December 31, In thousands 2018 2017 2016 Cash received (paid) on derivatives: Natural gas fixed price swaps $ (36,939 ) $ 40,095 $ 88,823 Natural gas collars — (10,539 ) — Cash received (paid) on derivatives, net (36,939 ) 29,556 88,823 Non-cash gain (loss) on derivatives: Crude oil written call options — — 38 Natural gas fixed price swaps 7,527 18,960 (120,784 ) Natural gas collars 5,482 43,131 (39,936 ) Non-cash gain (loss) on derivatives, net 13,009 62,091 (160,682 ) Gain (loss) on crude oil and natural gas derivatives, net $ (23,930 ) $ 91,647 $ (71,859 )
Balance sheet offsetting of derivative assets and liabilities	The following table presents the gross amounts of recognized natural gas derivative assets and liabilities, as applicable, 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 2018 2017 Commodity derivative assets: Gross amounts of recognized assets $ 16,789 $ 2,603 Gross amounts offset on balance sheet (1,177 ) — Net amounts of assets on balance sheet 15,612 2,603 Commodity derivative liabilities: Gross amounts of recognized liabilities (1,177 ) — Gross amounts offset on balance sheet 1,177 — Net amounts of liabilities on balance sheet $ — $ —
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 2018 2017 Derivative assets $ 15,612 $ 2,603 Noncurrent derivative assets — — Net amounts of assets on balance sheet 15,612 2,603 Derivative liabilities — — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — — Total derivative assets, net $ 15,612 $ 2,603

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 and 2017 . Fair value measurements at December 31, 2018 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 10,130 $ — $ 10,130 Collars — 5,482 — 5,482 Total $ — $ 15,612 $ — $ 15,612 Fair value measurements at December 31, 2017 using: In thousands Level 1 Level 2 Level 3 Total Derivative assets: Swaps $ — $ 2,603 $ — $ 2,603 Total $ — $ 2,603 $ — $ 2,603
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 strip prices through 2023 (adjusted for differentials), escalating 3% per year thereafter Operating costs Estimated costs for the current year, escalating 3% per year thereafter Productive life of properties Up to 50 years Discount rate 10% Unobservable inputs to the fair value assessment are reviewed quarterly and are revised as warranted based on a number of factors, including reservoir performance, new drilling, crude oil and natural gas prices, changes in costs, technological advances, new geological or geophysical data, or other economic factors. Fair value measurements of proved properties are reviewed and approved by certain members of the Company’s management.
Property Impairments	The following table sets forth the non-cash impairments of both proved and unproved properties for the indicated periods. Proved and unproved property impairments are recorded under the caption “Property impairments” in the consolidated statements of comprehensive income (loss). Year ended December 31, In thousands 2018 2017 2016 Proved property impairments $ 18,037 $ 82,340 $ 2,895 Unproved property impairments 107,173 155,030 234,397 Total $ 125,210 $ 237,370 $ 237,292
Fair Values of Financial Instruments not Recorded at Fair Value	The following table sets forth the estimated fair values of financial instruments that are not recorded at fair value in the consolidated financial statements. December 31, 2018 December 31, 2017 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Revolving credit facility $ — $ — $ 188,000 $ 188,000 Note payable 7,700 7,700 9,974 9,900 5% Senior Notes due 2022 1,598,404 1,590,900 1,997,576 2,040,000 4.5% Senior Notes due 2023 1,488,960 1,476,300 1,486,690 1,526,800 3.8% Senior Notes due 2024 993,151 947,200 992,036 988,800 4.375% Senior Notes due 2028 988,617 942,800 988,061 987,200 4.9% Senior Notes due 2044 691,517 618,800 691,354 679,900 Total debt $ 5,768,349 $ 5,583,700 $ 6,353,691 $ 6,420,600

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $39.4 million and $44.3 million at December 31, 2018 and 2017 , respectively, consists of the following. December 31, In thousands 2018 2017 Revolving credit facility $ — $ 188,000 Note payable 7,700 9,974 5% Senior Notes due 2022 1,598,404 1,997,576 4.5% Senior Notes due 2023 1,488,960 1,486,690 3.8% Senior Notes due 2024 993,151 992,036 4.375% Senior Notes due 2028 988,617 988,061 4.9% Senior Notes due 2044 691,517 691,354 Total debt 5,768,349 6,353,691 Less: Current portion of long-term debt 2,360 2,286 Long-term debt, net of current portion $ 5,765,989 $ 6,351,405
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, 2018 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $1,600,000 $1,500,000 $1,000,000 $1,000,000 $700,000 Maturity date Sep 15, 2022 April 15, 2023 June 1, 2024 January 15, 2028 June 1, 2044 Interest payment dates March 15, Sep 15 April 15, Oct 15 June 1, Dec 1 Jan 15, July 15 June 1, Dec 1 Make-whole redemption period (2) — Jan 15, 2023 Mar 1, 2024 Oct 15, 2027 Dec 1, 2043 (1) The Company has the option to redeem all or a portion of its remaining 2022 Notes at the decreasing redemption prices specified in the indenture related to the 2022 Notes plus any accrued and unpaid interest to the date of redemption. (2) At any time prior to the indicated 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 amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

Revenues (Tables)

Revenues (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]	The following table reflects the change in presentation of revenues and applicable expenses on the Company's 2018 results under the new and previous guidance. Year ended December 31, 2018 In thousands New Standard Prior Presentation Change Revenues: Crude oil and natural gas sales $ 4,678,722 $ 4,487,135 $ 191,587 Loss on natural gas derivatives, net (23,930 ) (23,930 ) — Crude oil and natural gas service operations 54,794 54,794 — Total revenues $ 4,709,586 $ 4,517,999 $ 191,587 Operating costs and expenses: Transportation expenses $ 191,587 $ — $ 191,587 Net income $ 989,700 $ 989,700 $ —
Disaggregation of Revenue [Table Text Block]	The following table presents the disaggregation of the Company's crude oil and natural gas revenues for the year ended December 31, 2018 . Year ended December 31, 2018 In thousands North Region South Region Total Crude oil revenues: Operated properties $ 2,330,711 $ 603,070 $ 2,933,781 Non-operated properties 790,435 68,378 858,813 Total crude oil revenues 3,121,146 671,448 3,792,594 Natural gas revenues: Operated properties 214,741 547,247 761,988 Non-operated properties 60,738 63,402 124,140 Total natural gas revenues 275,479 610,649 886,128 Crude oil and natural gas sales $ 3,396,625 $ 1,282,097 $ 4,678,722 Timing of revenue recognition Goods transferred at a point in time $ 3,396,625 $ 1,282,097 $ 4,678,722 Goods transferred over time — — — $ 3,396,625 $ 1,282,097 $ 4,678,722

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Provision for Income Taxes	The items comprising the Company's (provision) benefit for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2018 2017 2016 Current income tax (provision) benefit: United States federal (1) $ 7,781 $ 7,781 $ 22,941 Various states (5 ) — (2 ) Total current income tax benefit 7,776 7,781 22,939 Deferred income tax (provision) benefit: United States federal - taxation on operations (282,947 ) (81,054 ) 182,422 United States federal - effect of US tax reform — 713,655 — Various states (31,931 ) (7,002 ) 27,414 Total deferred income tax (provision) benefit (314,878 ) 625,599 209,836 (Provision) benefit for income taxes $ (307,102 ) $ 633,380 $ 232,775
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, 2018 2017 2016 In thousands, except rates Amount Rate Amount Rate Amount Rate Expected income tax (provision) benefit based on US statutory tax rate $ (272,328 ) 21.0 % $ (54,623 ) 35.0 % $ 221,359 35.0 % State income taxes, net of federal benefit (45,920 ) 3.6 % (4,682 ) 3.0 % 18,829 3.0 % Effect of US tax reform legislation — — % 713,655 (457.3 %) — — % Tax (benefit) deficiency from stock-based compensation 259 — % (3,932 ) 2.5 % — — % Non-deductible compensation (2,932 ) 0.2 % (13,813 ) 8.9 % (3,471 ) (0.5 %) Other, net 13,819 (1.1 %) (3,225 ) 2.1 % (3,942 ) (0.7 %) (Provision) benefit for income taxes $ (307,102 ) 23.7 % $ 633,380 (405.8 %) $ 232,775 36.8 %
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2018 and 2017 are reflected in the table below. December 31, In thousands 2018 2017 Deferred tax assets United States net operating loss carryforwards $ 549,166 $ 604,423 Canadian net operating loss carryforwards 19,633 19,341 Alternative minimum tax carryforwards — 7,781 Equity compensation 13,122 12,962 Other 13,622 21,885 Total deferred tax assets 595,543 666,392 Canadian valuation allowance (19,633 ) (19,341 ) Total deferred tax assets, net of valuation allowance 575,910 647,051 Deferred tax liabilities Property and equipment (2,144,767 ) (1,903,451 ) Other (5,579 ) (3,158 ) Total deferred tax liabilities (2,150,346 ) (1,906,609 ) Deferred income tax liabilities, net $ (1,574,436 ) $ (1,259,558 )

Lease Commitments (Tables)

Lease Commitments (Tables)	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Schedule of Minimum Future Rental Commitments Under Operating Leases	At December 31, 2018 , the minimum future rental commitments under operating leases having enforceable lease terms in excess of one year are reflected in the table below. Such commitments are reflected at undiscounted values and are not recognized on the Company's balance sheet at December 31, 2018 . In thousands Total amount 2019 $ 1,535 2020 1,042 2021 833 2022 805 2023 745 Thereafter 6,795 Total obligations $ 11,755

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2018
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 $47.2 million , $45.9 million , and $48.1 million for the years ended December 31, 2018 , 2017 and 2016 , 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, 2015 to December 31, 2018 is presented below. Number of Weighted Non-vested restricted shares at December 31, 2015 3,249,611 $ 48.20 Granted 2,064,508 22.36 Vested (1,207,235 ) 41.27 Forfeited (193,250 ) 39.79 Non-vested restricted shares at December 31, 2016 3,913,634 $ 37.12 Granted 1,585,870 44.58 Vested (874,665 ) 57.36 Forfeited (598,729 ) 37.34 Non-vested restricted shares at December 31, 2017 4,026,110 $ 35.63 Granted 1,390,914 52.71 Vested (1,116,329 ) 46.19 Forfeited (278,286 ) 38.06 Non-vested restricted shares at December 31, 2018 4,022,409 $ 38.44

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2018
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 income (loss) for the years ended December 31, 2018 , 2017 , and 2016 : Year ended December 31, In thousands 2018 2017 2016 Beginning accumulated other comprehensive income (loss), net of tax $ 307 $ (260 ) $ (3,354 ) Foreign currency translation adjustments 108 567 3,094 Income taxes (1) — — — Other comprehensive income, net of tax 108 567 3,094 Ending accumulated other comprehensive income (loss), net of tax $ 415 $ 307 $ (260 ) (1) A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Crude Oil and Natural Gas Pro_2

Crude Oil and Natural Gas Property Information (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 2017 and 2016 . Year ended December 31, In thousands 2018 2017 2016 Crude oil and natural gas sales (1) $ 4,678,722 $ 2,982,966 $ 2,026,958 Production expenses (390,423 ) (324,214 ) (289,289 ) Production taxes (353,140 ) (208,278 ) (142,388 ) Transportation expenses (1) (191,587 ) — — Exploration expenses (7,642 ) (12,393 ) (16,972 ) Depreciation, depletion, amortization and accretion (1,839,241 ) (1,652,180 ) (1,679,485 ) Property impairments (125,210 ) (237,370 ) (237,292 ) Income tax (provision) benefit (2) (434,047 ) 504,475 126,794 Results from crude oil and natural gas producing activities $ 1,337,432 $ 1,053,006 $ (211,674 )
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, 2018 , 2017 and 2016 are presented below: Year ended December 31, In thousands 2018 2017 2016 Property acquisition costs: Proved $ 31,579 $ 8,446 $ 5,008 Unproved 329,586 220,875 149,962 Total property acquisition costs 361,165 229,321 154,970 Exploration Costs 81,015 123,461 182,355 Development Costs 2,478,327 1,695,954 767,148 Total $ 2,920,507 $ 2,048,736 $ 1,104,473
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, 2018 and 2017 are as follows: December 31, In thousands 2018 2017 Proved crude oil and natural gas properties $ 24,060,625 $ 21,362,199 Unproved crude oil and natural gas properties 291,564 365,413 Total 24,352,189 21,727,612 Less accumulated depreciation, depletion and amortization (10,680,870 ) (8,971,935 ) Net capitalized costs $ 13,671,319 $ 12,755,677
Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation	The following table presents the amount of capitalized exploratory well 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 2018 2017 2016 Balance at January 1 $ 31,356 $ 34,852 $ 59,397 Additions to capitalized exploratory well costs pending determination of proved reserves 45,088 79,451 123,980 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (72,347 ) (81,035 ) (141,941 ) Capitalized exploratory well costs charged to expense (138 ) (1,912 ) (6,584 ) Balance at December 31 $ 3,959 $ 31,356 $ 34,852 Number of gross wells 16 37 54

Supplemental Crude Oil and Na_2

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2015 700,514 3,151,786 1,225,811 Revisions of previous estimates (99,966 ) (63,057 ) (110,474 ) Extensions, discoveries and other additions 97,587 911,062 249,430 Production (46,850 ) (195,240 ) (79,390 ) Sales of minerals in place (8,057 ) (14,733 ) (10,513 ) Purchases of minerals in place — — — Proved reserves as of December 31, 2016 643,228 3,789,818 1,274,864 Revisions of previous estimates (77,779 ) (25,390 ) (82,012 ) Extensions, discoveries and other additions 129,895 661,867 240,206 Production (50,536 ) (228,159 ) (88,562 ) Sales of minerals in place (4,365 ) (64,989 ) (15,197 ) Purchases of minerals in place 506 7,134 1,696 Proved reserves as of December 31, 2017 640,949 4,140,281 1,330,995 Revisions of previous estimates (76,994 ) (1,153,555 ) (269,253 ) Extensions, discoveries and other additions 253,066 1,871,777 565,030 Production (61,384 ) (284,730 ) (108,839 ) Sales of minerals in place (2,154 ) (35,142 ) (8,011 ) Purchases of minerals in place 3,613 52,983 12,443 Proved reserves as of December 31, 2018 757,096 4,591,614 1,522,365
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, 2018 , 2017 and 2016 : December 31, 2018 2017 2016 Proved Developed Reserves Crude oil (MBbl) 347,825 318,707 290,210 Natural Gas (MMcf) 1,964,289 1,699,161 1,370,620 Total (MBoe) 675,206 601,901 518,646 Proved Undeveloped Reserves Crude oil (MBbl) 409,271 322,242 353,018 Natural Gas (MMcf) 2,627,325 2,441,120 2,419,198 Total (MBoe) 847,159 729,094 756,218 Total Proved Reserves Crude oil (MBbl) 757,096 640,949 643,228 Natural Gas (MMcf) 4,591,614 4,140,281 3,789,818 Total (MBoe) 1,522,365 1,330,995 1,274,864
Standardized Measure of Discounted Future Net Cash Flows	The following table sets forth the standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves as of December 31, 2018 , 2017 and 2016 . Discounted future net cash flows attributable to noncontrolling interests are immaterial and are not separately presented below. December 31, In thousands 2018 2017 2016 Future cash inflows $ 61,510,432 $ 42,574,897 $ 31,008,587 Future production costs (16,139,001 ) (11,159,362 ) (9,175,410 ) Future development and abandonment costs (9,706,114 ) (6,487,097 ) (6,452,647 ) Future income taxes (1) (6,012,439 ) (3,488,755 ) (3,018,839 ) Future net cash flows 29,652,878 21,439,683 12,361,691 10% annual discount for estimated timing of cash flows (13,968,061 ) (10,969,506 ) (6,851,468 ) Standardized measure of discounted future net cash flows $ 15,684,817 $ 10,470,177 $ 5,510,223
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 proved crude oil and natural gas reserves are presented below for each of the past three years. December 31, In thousands 2018 2017 2016 Standardized measure of discounted future net cash flows at January 1 $ 10,470,177 $ 5,510,223 $ 6,476,284 Extensions, discoveries and improved recoveries, less related costs 5,162,635 1,462,629 786,587 Revisions of previous quantity estimates (3,522,428 ) (1,004,355 ) (794,785 ) Changes in estimated future development and abandonment costs 1,063,089 743,657 1,651,218 Sales of minerals in place, net (9,192 ) (41,077 ) (90,390 ) Net change in prices and production costs 4,224,473 3,808,116 (2,003,163 ) Accretion of discount 1,183,347 665,507 798,597 Sales of crude oil and natural gas produced, net of production costs (3,743,572 ) (2,450,474 ) (1,595,281 ) Development costs incurred during the period 1,134,153 1,045,875 454,983 Change in timing of estimated future production and other 1,324,365 948,519 (538,665 ) Change in income taxes (1,602,230 ) (218,443 ) 364,838 Net change 5,214,640 4,959,954 (966,061 ) Standardized measure of discounted future net cash flows at December 31 $ 15,684,817 $ 10,470,177 $ 5,510,223

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2018 and 2017 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2018 Total revenues (1) $ 1,141,028 $ 1,137,113 $ 1,282,151 $ 1,149,294 Gain (loss) on natural gas derivatives, net (1) $ 10,174 $ (12,685 ) $ (2,025 ) $ (19,394 ) Property impairments (2) $ 33,784 $ 29,162 $ 23,770 $ 38,494 Gain on sale of assets, net (3) $ 41 $ 6,710 $ 1,510 $ 8,410 Income from operations $ 380,722 $ 391,276 $ 491,308 $ 330,414 Loss on extinguishment of debt (4) $ — $ — $ (7,133 ) $ — Net income $ 233,946 $ 242,464 $ 314,169 $ 199,121 Net income attributable to Continental Resources $ 233,946 $ 242,464 $ 314,169 $ 197,738 Net income per share attributable to Continental Resources: Basic $ 0.63 $ 0.65 $ 0.84 $ 0.53 Diluted $ 0.63 $ 0.65 $ 0.84 $ 0.53 2017 Total revenues (1) $ 685,427 $ 661,486 $ 726,743 $ 1,047,172 Gain on natural gas derivatives, net (1) $ 46,858 $ 28,022 $ 8,602 $ 8,165 Property impairments (2) $ 51,372 $ 123,316 $ 35,130 $ 27,552 Litigation settlement (5) $ — $ — $ — $ 59,600 Gain (loss) on sale of assets, net (3) $ (3,638 ) $ 780 $ 3,562 $ 54,420 Income (loss) from operations $ 77,221 $ (29,041 ) $ 91,753 $ 309,468 Net income (loss) (6) $ 469 $ (63,557 ) $ 10,621 $ 841,914 Net income (loss) per share: Basic $ — $ (0.17 ) $ 0.03 $ 2.27 Diluted $ — $ (0.17 ) $ 0.03 $ 2.25 (1) Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Natural gas 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. Additionally, beginning in 2018 certain transportation expenses are no longer netted within "Total revenues" as a result of the Company's January 1, 2018 prospective adoption of ASU 2016-08, which affects comparability of 2017 and 2018 revenues. Transportation expenses totaled $49.3 million , $47.3 million , $46.0 million , and $49.0 million for the first, second, third, and fourth quarters of 2018, respectively. (2) Property impairments have been shown separately to illustrate the impact on quarterly results 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) Gains and losses on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 16. Property Dispositions for a discussion of notable dispositions. (4) See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the partial redemption of its 2022 Notes in the 2018 third quarter. (5) Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies—Litigation , which resulted in an after-tax decrease in net income of $37.0 million ( $0.10 per basic and diluted share). (6) Fourth quarter 2017 results reflect the remeasurement of the Company's deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017, which resulted in a one-time decrease in income tax expense and corresponding increase in net income of approximately $713.7 million ( $1.92 per basic share and $1.91 per diluted share). See Note 9. Income Taxes for further discussion.

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended					12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Organization And Summary Of Significant Accounting Policies [Line Items]
Tax benefit from US tax reform legislation						$ 0	$ (713,655)	$ 0
Accrued litigation settlement	$ 19,753				$ 59,600	19,753	59,600
Cumulative Effect on Retained Earnings, Net of Tax							5,150
Allowance for Doubtful Accounts Receivable	2,400				2,200	2,400	2,200
Unamortized Debt Issuance Expense	45,100				55,000	45,100	55,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount						300	400	1,000
Cash deposits in excess of federally insured amounts	280,700					280,700
Net asset retirement costs	57,700				40,000	57,700	40,000
Capitalized debt issue costs, relating to long-term debt	51,200				58,200	51,200	58,200
Accumulated amortization, relating to capitalized debt issue costs	62,500				51,800	62,500	51,800
Amortization expense related to capitalized debt issuance costs						9,300	9,100	9,800
Deferred Tax Assets, Valuation Allowance	19,633				$ 19,341	19,633	19,341
Transportation expenses	49,000	$ 46,000	$ 47,300	$ 49,300		191,587	0	$ 0
Estimated litigation liability, after tax							$ 37,000
Basic eps litigation settlement					$ 0.10
Diluted eps estimated litigation settlement							$ 0.10
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 6,100				$ 3,200	$ 6,100	$ 3,200
Customer one concentration [Member] | Oil And Natural Gas [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Percentage of crude oil sales to one single purchaser accounted on total revenues						12.00%

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 14,623	$ 14,946
Crude oil	73,921	82,460
Total	$ 88,544	$ 97,406

Organization and Summary of S_6

Organization and Summary of Significant Accounting Policies - Schedule of Estimated Useful Lives of Service Property and Equipment (Detail)	12 Months Ended
	Dec. 31, 2018
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)	4 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)	25 years
Maximum [Member] | Buildings And Improvements [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	40 years

Organization and Summary of S_7

Organization and Summary of Significant Accounting Policies - Summary Of Changes In Future Abandonment Liabilities (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 114,406	$ 96,178	$ 102,909
Accretion expense		6,985	5,886	6,086
Revisions	[1]	13,075	7,801	(12,755)
Plus: Additions for new assets		9,070	6,884	2,692
Less: Plugging costs and sold assets		(2,176)	(2,343)	(2,754)
Total asset retirement obligations at December 31		141,360	114,406	96,178
Less: Current portion of asset retirement obligations at December 31	[2]	4,374	2,612	1,742
Non-current portion of asset retirement obligations at December 31		$ 136,986	$ 111,794	$ 94,436
[1]	Revisions primarily represent changes in the present value of liabilities resulting from changes in estimated costs and economic lives of producing properties.
[2]	Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

Organization and Summary of S_8

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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basic EPS impact from tax benefit from US tax reform										$ 1.92
Diluted EPS impact from tax benefit from US tax reform										$ 1.91
Weighted average number diluted shares excluded from calculation											2,303,000
Income (numerator):
Net income - basic and diluted	$ 197,738	$ 314,169	$ 242,464	$ 233,946	$ 841,914	$ 10,621	$ (63,557)	$ 469	$ 988,317	$ 789,447	$ (399,679)
Weighted average shares - basic									371,854,000	371,066,000	370,380,000
Non-vested restricted stock									2,984,000	2,702,000	0	[1]
Weighted average shares - diluted									374,838,000	373,768,000	370,380,000
Net income per share:
Basic (in dollars per share)	$ 0.53	$ 0.84	$ 0.65	$ 0.63	$ 2.27	$ 0.03	$ (0.17)	$ 0	$ 2.66	$ 2.13	$ (1.08)
Diluted (in dollars per share)	$ 0.53	$ 0.84	$ 0.65	$ 0.63	$ 2.25	$ 0.03	$ (0.17)	$ 0	$ 2.64	$ 2.11	$ (1.08)
[1]	For the year ended December 31, 2016, the Company had a net loss and therefore the potential dilutive effect of approximately 2,303,000 weighted average non-vested restricted shares were not included in the calculation of diluted net loss per share because to do so would have been anti-dilutive to the computation.

Organization and Summary of S_9

Organization and Summary of Significant Accounting Policies Organization and Summary of Significant Accounting Policies - New Accounting Pronouncement (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
New Accounting Pronouncements [Abstract]
Lease estimated discount rate	4.50%
Estimated lease assets and liabilities	$ 19
lease standard weighted average year	5 years 5 months

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Cash Flow Information [Abstract]
Capital Expenditures Incurred but Not yet Paid	$ 317,500	$ 302,800
Supplemental cash flow information:
Cash paid for interest	270,927	281,058	$ 316,116
Cash paid for income taxes	0	2	2
Cash received for income tax refunds	7,893	257	174
Asset Retirement Obligation, Additions or Revisions	$ 22,145	$ 14,685	$ (10,063)

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 24,060,625	$ 21,362,199
Unproved crude oil and natural gas properties	291,564	365,413
Service properties, equipment and other	324,758	290,111
Total property and equipment	24,676,947	22,017,723
Accumulated depreciation, depletion and amortization	(10,807,147)	(9,083,934)
Net property and equipment	$ 13,869,800	$ 12,933,789

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 53,674	$ 34,511
Accrued compensation		69,338	65,308
Accrued production taxes, ad valorem taxes and other non-income taxes		52,105	40,611
Accrued interest		64,483	55,282
Accrued litigation settlement		19,753	59,600
Current portion of asset retirement obligations	[1]	4,374	2,612	$ 1,742
Other		3,092	2,150
Accrued liabilities and other		$ 266,819	$ 260,074
[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 Natural Gas (Detail) - Natural Gas [Member]	12 Months Ended
	Dec. 31, 2018MMBTU$ / MMBTU
January 2019 to March 2019 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	4,950,000
Swaps Weighted Average Price	4.70
April 2019 to December 2019 Swaps [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	95,425,000
Swaps Weighted Average Price	2.78
January 2019 to March 2019 Collars [Member]
Derivative [Line Items]
Natural Gas Production Derivative Volume, MMBtus | MMBTU	4,950,000
Floors, weighted average price	4.25
Ceilings, weighted average price	5.52
Maximum [Member] | January 2019 to March 2019 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	4.25
Derivative, Cap Price	5.58
Minimum [Member] | January 2019 to March 2019 Collars [Member]
Derivative [Line Items]
Derivative, Floor Price	4.25
Derivative, Cap Price	5.50

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, 2018	[1]	Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2017	[1]	Sep. 30, 2017	[1]	Jun. 30, 2017	[1]	Mar. 31, 2017	[1]	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ 13,009	$ 58,031	$ (156,621)
Gain (loss) on crude oil and natural gas derivatives, net	$ (19,394)		$ (2,025)		$ (12,685)		$ 10,174		$ 8,165		$ 8,602		$ 28,022		$ 46,858		(23,930)	91,647	(71,859)
Fuel [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																		2,845	699
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																		(4,060)	4,060
Gain (loss) on crude oil and natural gas derivatives, net																		(1,215)	4,759
Fixed Price Swaps [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	(36,939)	40,095	88,823
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	7,527	18,960	(120,784)
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	0	(10,539)	0
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	5,482	43,131	(39,936)
Call Option [Member] | Crude Oil [Member]
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	0	0	38
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	(36,939)	29,556	88,823
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	13,009	62,091	(160,682)
Gain (loss) on crude oil and natural gas derivatives, net																	$ (23,930)	$ 91,647	$ (71,859)
[1]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Natural gas 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. Additionally, beginning in 2018 certain transportation expenses are no longer netted within "Total revenues" as a result of the Company's January 1, 2018 prospective adoption of ASU 2016-08, which affects comparability of 2017 and 2018 revenues. Transportation expenses totaled $49.3 million, $47.3 million, $46.0 million, and $49.0 million for the first, second, third, and fourth quarters of 2018, respectively.

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 16,789	$ 2,603
Commodity derivative assets, Gross amounts offset on balance sheet	(1,177)	0
Derivative assets, Net amounts of assets on balance sheet	15,612	2,603
Commodity derivative liability, Gross amounts of recognized liabilities	(1,177)	0
Commodity derivative liability, Gross amounts offset on balance sheet	1,177	0
Derivative liability, Net amounts of liabilities on balance sheet	$ 0	$ 0

Derivative Instruments Deriva_2

Derivative Instruments Derivative Instruments - Reconciles Net Amounts Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 15,612	$ 2,603
Noncurrent derivative assets	0	0
Derivative assets, Net amounts of assets on balance sheet	15,612	2,603
Derivative liabilities	0	0
Noncurrent derivative liabilities	0	0
Derivative liability, Net amounts of liabilities on balance sheet	0	0
Total derivative assets, net	$ 15,612	$ 2,603

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 15,612	$ 2,603
Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	10,130	2,603
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	5,482
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
Fair Value, Inputs, Level 2 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	15,612	2,603
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	10,130	2,603
Fair Value, Inputs, Level 2 [Member] | Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)	5,482
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

Fair Value Measurements - Addit

Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2017	Sep. 30, 2016
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	$ 18,037	$ 82,340	$ 2,895
Estimated fair value of proved properties				$ 72,000	$ 700
Minimum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	1 year
Maximum [Member]
Fair Value Measurements [Line Items]
Productive life of field (in years)	50 years
Forward Commodity Prices [Member]
Fair Value Measurements [Line Items]
Forward commodity price escalation assumption used in impairment assessment	3.00%
Non-core [Member]
Fair Value Measurements [Line Items]
Impairments of proved properties		$ 1,100

Fair Value Measurements - Prope

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

[1]

Sep. 30, 2018

[1]

Jun. 30, 2018

[1]

Mar. 31, 2018

[1]

Dec. 31, 2017

[1]

Sep. 30, 2017

[1]

Jun. 30, 2017

Mar. 31, 2017

[1]

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

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

Proved property impairments

$ 18,037

$ 82,340

$ 2,895

Unproved property impairments

107,173

155,030

234,397

Total

$ 38,494

$ 23,770

$ 29,162

$ 33,784

$ 27,552

$ 35,130

$ 123,316

[1]

$ 51,372

$ 125,210

237,370

$ 237,292

Estimated fair value of proved properties

$ 72,000

$ 700

Arkoma Woodford [Member]

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

Proved property impairments

81,200

Non-core [Member]

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

Proved property impairments

$ 1,100

[1]

Property impairments have been shown separately to illustrate the impact on quarterly results 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, 2018	Dec. 31, 2017
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		$ 992,036
4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2,028
Debt instrument, stated interest rate	4.375%
Senior notes		988,061
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		691,354
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	$ 0	188,000
Note payable	7,700	9,974
Total debt	5,768,349	6,353,691
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,598,404	1,997,576
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,488,960	1,486,690
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	993,151	992,036
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	988,617	988,061
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	691,517	691,354
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	0	188,000
Note payable	7,700	9,900
Total debt	5,583,700	6,420,600
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,590,900	2,040,000
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,476,300	1,526,800
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	947,200	988,800
Fair Value [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	942,800	987,200
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 618,800	$ 679,900

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 16, 2018
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	$ 39,400								$ 39,400	$ 44,300
TotalRedemptionAmount												$ 415,100
Less: Current portion of long-term debt	(2,360)								(2,360)	(2,286)
Long-term debt, net of current portion	5,765,989								5,765,989	6,351,405
Loss on extinguishment of debt	$ 0	[1]	$ (7,133)		$ 0		$ 0		$ (7,133)	(554)	$ (26,055)
5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	5.00%								5.00%
4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, stated interest rate	4.50%								4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes										992,036
Debt instrument, stated interest rate	3.80%								3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes										988,061
Debt instrument, stated interest rate	4.375%								4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes										691,354
Debt instrument, stated interest rate	4.90%								4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 0								$ 0	188,000
Note payable	7,700								7,700	9,974
Total debt	5,768,349								5,768,349	6,353,691
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,598,404								1,598,404	1,997,576
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,488,960								1,488,960	1,486,690
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	993,151								993,151	992,036
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	988,617								988,617	988,061
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,517								$ 691,517	$ 691,354
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the partial redemption of its 2022 Notes in the 2018 third quarter.

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Aug. 16, 2018
Debt Instrument [Line Items]
Proceeds from sale of assets									$ 214,800	$ 54,458	$ 144,353	$ 631,549
Loss on extinguishment of debt	$ 0	[1]	$ 7,133	[1]	$ 0		$ 0			7,133	554	26,055
TotalRedemptionAmount													$ 415,100
Aggregate amount of lender commitments on credit facility	1,500,000									1,500,000
Line of Credit Facility, Maximum Borrowing Capacity	4,000,000									$ 4,000,000
Line of credit facility, commitment fee percentage, per annum										0.20%
Line of Credit Facility, Covenant Terms										0.65
Proceeds from issuance of Senior Notes										$ 0	990,000	0
Repayments of Lines of Credit										2,212,000	2,019,000	$ 1,639,000
Current portion of long-term debt	2,360									2,360	2,286
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount													$ 400,000
Debt Instrument, Redemption Price, Percentage of Principal Amount Redeemed			20.00%
Debt Instrument, Redemption Price, Percentage			101.667%
Debt Instrument, Face Amount	1,600,000									$ 1,600,000
Debt instrument, maturity date										Sep. 15, 2022
Senior Notes due 2028 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	1,000,000									$ 1,000,000
Debt instrument, maturity date										Jan. 15, 2028
Note Payable [Member]
Debt Instrument [Line Items]
Notes Payable	$ 22,000									$ 22,000
Loan period, in years										10 years
Debt instrument, stated interest rate	3.14%									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%									5.00%
Senior Notes Due 2023 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,500,000									$ 1,500,000
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%									4.50%
3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes											992,036
Debt instrument, stated interest rate	3.80%									3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes											988,061
Debt instrument, stated interest rate	4.375%									4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes											691,354
Debt instrument, stated interest rate	4.90%									4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 0									$ 0	188,000
Notes Payable	7,700									7,700	9,974
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,598,404									1,598,404	1,997,576
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,488,960									1,488,960	1,486,690
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	993,151									993,151	992,036
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	988,617									988,617	988,061
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,517									$ 691,517	$ 691,354
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the partial redemption of its 2022 Notes in the 2018 third quarter.

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, 2018USD ($)
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,600,000
Maturity date	Sep. 15, 2022
Interest Payment Dates	March 15,  Sep 15
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	[1]
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	[1]
Senior Notes due 2028 [Domain]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,000,000
Maturity date	Jan. 15, 2028
Interest Payment Dates	Jan 15, July 15
Make-whole redemption period	Oct. 15, 2027	[1]
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	[1]
[1]	At any time prior to the indicated 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 amounts specified in the respective senior note indentures plus any accrued and unpaid interest to the date of redemption. On or after the indicated dates, the Company may redeem all or a portion of its senior notes at a redemption amount equal to 100% of the principal amount of the senior notes being redeemed plus any accrued and unpaid interest to the date of redemption.

Revenues (Details)

Revenues (Details) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Item Effected [Line Items]
Crude oil and natural gas sales																	$ 4,678,722	$ 2,982,966	$ 2,026,958
Gain (loss) on crude oil and natural gas derivatives, net	$ (19,394)	[1]	$ (2,025)	[1]	$ (12,685)	[1]	$ 10,174	[1]	$ 8,165	[1]	$ 8,602	[1]	$ 28,022	[1]	$ 46,858	[1]	(23,930)	91,647	(71,859)
Crude oil and natural gas service operations																	54,794	46,215	25,174
Total revenues	1,149,294	[1]	1,282,151	[1]	1,137,113	[1]	1,141,028	[1]	1,047,172	[1]	726,743	[1]	661,486	[1]	685,427	[1]	4,709,586	3,120,828	1,980,273
Transportation expenses	49,000		46,000		47,300		49,300										191,587	0	0
Net income (loss)	199,121		314,169		242,464		233,946										989,700	789,447	(399,679)
Net income (loss) attributable to Continental Resources	$ 197,738		$ 314,169		$ 242,464		$ 233,946		$ 841,914		$ 10,621		$ (63,557)		$ 469		988,317	$ 789,447	$ (399,679)
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Item Effected [Line Items]
Crude oil and natural gas sales																	4,487,135
Gain (loss) on crude oil and natural gas derivatives, net																	(23,930)
Crude oil and natural gas service operations																	54,794
Total revenues																	4,517,999
Transportation expenses																	0
Net income (loss) attributable to Continental Resources																	989,700
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Item Effected [Line Items]
Crude oil and natural gas sales																	191,587
Gain (loss) on crude oil and natural gas derivatives, net																	0
Crude oil and natural gas service operations																	0
Total revenues																	191,587
Transportation expenses																	191,587
Net income (loss) attributable to Continental Resources																	$ 0
[1]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Natural gas 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. Additionally, beginning in 2018 certain transportation expenses are no longer netted within "Total revenues" as a result of the Company's January 1, 2018 prospective adoption of ASU 2016-08, which affects comparability of 2017 and 2018 revenues. Transportation expenses totaled $49.3 million, $47.3 million, $46.0 million, and $49.0 million for the first, second, third, and fourth quarters of 2018, respectively.

Revenues Revenues Disaggregatio

Revenues Revenues Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Transportation expenses	$ 49,000	$ 46,000	$ 47,300	$ 49,300	$ 191,587	$ 0	$ 0
Crude oil and natural gas sales					4,678,722	$ 2,982,966	$ 2,026,958
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					4,678,722
Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					0
North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					3,396,625
North Region [Member] | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					3,396,625
North Region [Member] | Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					0
South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					1,282,097
South Region [Member] | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					1,282,097
South Region [Member] | Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					0
Crude oil sales
Disaggregation of Revenue [Line Items]
Transportation expenses					162,300
Crude oil and natural gas sales					3,792,594
Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					3,121,146
Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					671,448
Natural gas sales
Disaggregation of Revenue [Line Items]
Transportation expenses					29,300
Crude oil and natural gas sales					886,128
Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					275,479
Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					610,649
Operated properties | Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					2,933,781
Operated properties | Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					2,330,711
Operated properties | Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					603,070
Operated properties | Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					761,988
Operated properties | Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					214,741
Operated properties | Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					547,247
Non-operated properties | Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					858,813
Non-operated properties | Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					790,435
Non-operated properties | Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					68,378
Non-operated properties | Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					124,140
Non-operated properties | Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					60,738
Non-operated properties | Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales					$ 63,402

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Current federal income tax (provision) benefit	$ 7,781	$ 7,781	$ 22,941
Current tax (provision), various states	(5)	0	(2)
Total current income tax benefit	7,776	7,781	22,939
Deferred federal income tax (provision) benefit	(282,947)	(81,054)	182,422
Tax benefit from US tax reform legislation	0	713,655	0
Deferred tax (provision) benefit, various states	(31,931)	(7,002)	27,414
Total deferred income tax (provision) benefit	(314,878)	625,599	209,836
(Provision) benefit for income taxes	$ (307,102)	$ 633,380	$ 232,775

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Expected income tax (provision) benefit based on US statutory tax rate	$ (272,328)	$ (54,623)	$ 221,359
State income taxes, net of federal benefit	(45,920)	(4,682)	18,829
Tax benefit from US tax reform legislation	0	713,655	0
Tax deficiency from stock-based compensation	259	(3,932)	0
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Compensation Cost, Amount	(2,932)	(13,813)	(3,471)
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	300	400	1,000
Other, net	13,819	(3,225)	(3,942)
(Provision) benefit for income taxes	$ (307,102)	$ 633,380	$ 232,775
Federal statutory income tax rate	21.00%	35.00%
Effective tax rate	23.70%	(405.80%)	36.80%

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Deferred tax assets, Net operating loss carryforwards	$ 549,166	$ 604,423
Deferred tax assets, Canadian net operating loss carryforwards	19,633	19,341
Deferred tax assets, Alternative minimum tax carryforwards	0	7,781
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	13,122	12,962
Deferred Tax Assets, Other	13,622	21,885
Total deferred tax assets	595,543	666,392
Deferred Tax Assets, Valuation Allowance	(19,633)	(19,341)
Deferred Tax Assets, Net	575,910	647,051
Deferred tax liabilities, Property and equipment	(2,144,767)	(1,903,451)
Deferred Tax Liabilities, Other	(5,579)	(3,158)
Total deferred tax liabilities	(2,150,346)	(1,906,609)
Net deferred tax liabilities	$ (1,574,436)	$ (1,259,558)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 3,170,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	300	$ 400	$ 1,000
Deferred Tax Assets, Valuation Allowance	19,633	$ 19,341
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	1,950,000
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	2,140,000
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 900,000

Lease Commitments - Lease Commi

Lease Commitments - Lease Commitments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Leases [Abstract]
Lease expenses associated with operating leases	$ 2,000	$ 1,900	$ 4,400
2,019	1,535
2,020	1,042
2,021	833
2,022	805
2,023	745
Thereafter	6,795
Total obligations	$ 11,755

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Long-term Purchase Commitment [Line Items]
Total future drilling commitments at balance sheet date	$ 107
Drilling commitments due year one	106
Drilling commitments due year two	1
Estimated lease assets and liabilities drilling rig	$ 13
Future Drilling Commitments End Date	2020-02
Pipeline Transportation and Processing Commitments [Member]
Long-term Purchase Commitment [Line Items]
Future commitment, end date	2,028
Future commitment, total	$ 1,832
Future commitment, due year one	241
Future commitment, due year two	273
Future commitment, due year three	254
Future commitment, due year four	249
Future commitment, due year five	248
Future commitments, thereafter	$ 566

Commitments and Contingencies L

Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Thousands	3 Months Ended
	Sep. 30, 2018	Dec. 31, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Accrued litigation settlement		$ 19,753	$ 59,600
Legal proceedings recorded as a liability under other noncurrent liabilities		4,700	7,600
Strack royalty payment litigation [Member]
Loss Contingencies [Line Items]
Accrued litigation settlement		$ 19,800	$ 59,600
Settlement payment	$ 45,800

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Related Party Transaction [Line Items]
Amount charged to affiliate for aircraft use	$ 12,900	$ 19,400	$ 9,500
Amount charged to company by affiliate for aircraft use	598,000	460,000	292,000
Affiliated Entity [Member]
Related Party Transaction [Line Items]
Capitalized costs			100,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	200,000	300,000	300,000
Due to affiliates	41,000	48,000
Revenues paid to related party	500,000	500,000	400,000
Due from affiliates	67,000	58,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	529,000	368,000	195,000
Due to affiliates	161,000	92,000
Due from affiliates	2,700	4,200
Total amount received from related party	$ 14,400	$ 18,600	$ 7,000

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation	$ 47,236	$ 45,868	$ 48,098

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 61	$ 39.8	$ 30
Unrecognized compensation expense related to non-vested	$ 70
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year
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	13,736,734

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	4,026,110	3,913,634	3,249,611
Granted shares	1,390,914	1,585,870	2,064,508
Vested shares	(1,116,329)	(874,665)	(1,207,235)
Forfeited shares	(278,286)	(598,729)	(193,250)
Non-vested shares, ending balance	4,022,409	4,026,110	3,913,634
Non-vested, weighted average grant-date fair value, beginning of period	$ 35.63	$ 37.12	$ 48.20
Granted, weighted average grant-date fair value	52.71	44.58	22.36
Vested, weighted average grant-date fair value	46.19	57.36	41.27
Forfeited, weighted average grant-date fair value	38.06	37.34	39.79
Non-vested, weighted average grant-date fair value, end of period	$ 38.44	$ 35.63	$ 37.12

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Foreign Currency [Abstract]
Foreign currency translation adjustments		$ 108	$ 567	$ 3,094
Translation Adjustment Functional to Reporting Currency, Tax Benefit (Expense)	[1]	0	0	0
Other Comprehensive Income (Loss), Net of Tax		108	567	3,094
Accumulated other comprehensive loss		$ 415	$ 307	$ (260)	$ (3,354)
[1]	A valuation allowance has been recognized against all deferred tax assets associated with losses generated by the Company’s Canadian operations, thereby resulting in no income taxes on other comprehensive income.

Noncontrolling Interests (Detai

Noncontrolling Interests (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Noncontrolling Interest [Line Items]
Equity transaction costs		$ 4,838	$ 0	$ 0
TMRC II [Member]
Noncontrolling Interest [Line Items]
Proceeds from formation of new mineral relationship	$ 214,800
Funding of future mineral acquisitions	309,000	309,000
Other Noncontrolling Interests	266,800	266,800
SFPG, LLC [Member]
Noncontrolling Interest [Line Items]
Other Noncontrolling Interests	$ 9,900	$ 9,900
Continental Resources ownership in TMRCII [Member] | TMRC II [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	50.10%	50.10%
Franco-Nevada Corporation ownership in TMRCII [Member] | TMRC II [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Noncontrolling Owners	49.90%	49.90%
Continental Resources ownership in SFPG, LLC [Member] | SFPG, LLC [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Ownership Percentage by Parent	57.40%	57.40%

Property Dispositions - Additio

Property Dispositions - Additional Information (Detail) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2018USD ($)

[1]

Sep. 30, 2018USD ($)

[1]

Jun. 30, 2018USD ($)

[1]

Mar. 31, 2018USD ($)

[1]

Dec. 31, 2017USD ($)

[1]

Sep. 30, 2017USD ($)aBoe

Jun. 30, 2017USD ($)

[1]

Mar. 31, 2017USD ($)

[1]

Dec. 31, 2016USD ($)Boe

Sep. 30, 2016aBoe

Jun. 30, 2016USD ($)a

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Oct. 14, 2016a

Property Acquisition And Dispositions [Line Items]

Proceeds from sale of assets

$ 214,800

$ 54,458

$ 144,353

$ 631,549

Gain (Loss) on Disposition of Property Plant Equipment

$ 8,410

$ 1,510

$ 6,710

$ 41

$ 54,420

$ 3,562

[1]

$ 780

$ (3,638)

$ (16,671)

(55,124)

$ (304,489)

Proceeds from sale of non-producing leasehold

295,600

$ 110,000

Gain (Loss) on disposition of non-producing leasehold

$ 201,000

$ 96,900

STACK [Member]

Property Acquisition And Dispositions [Line Items]

Proceeds from Sale of Oil and Gas Property and Equipment

63,500

Gain (Loss) on Disposition of Property Plant Equipment

56,900

Arkoma Woodford [Member]

Property Acquisition And Dispositions [Line Items]

Proceeds from Sale of Oil and Gas Property and Equipment

65,300

Land Subject to Ground Leases | a

26,000

Production, Barrels of Oil Equivalents | Boe

1,700

Gain (Loss) on disposition of non-producing leasehold

(3,500)

OKLAHOMA

Property Acquisition And Dispositions [Line Items]

Proceeds from Sale of Oil and Gas Property and Equipment

7,200

Gain (Loss) on disposition of oil loading facilities

$ 4,200

SCOOP [Member]

Property Acquisition And Dispositions [Line Items]

Land Subject to Ground Leases | a

30,000

Production, Barrels of Oil Equivalents | Boe

700

WYOMING

Property Acquisition And Dispositions [Line Items]

Land Subject to Ground Leases | a

132,000

NORTH DAKOTA

Property Acquisition And Dispositions [Line Items]

Land Subject to Ground Leases | a

68,000

MONTANA

Property Acquisition And Dispositions [Line Items]

Land Subject to Ground Leases | a

12,000

BAKKEN [Domain]

Property Acquisition And Dispositions [Line Items]

Production, Barrels of Oil Equivalents | Boe

2,700

[1]

Gains and losses on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 16. Property Dispositions for a discussion of notable dispositions.

Crude Oil and Natural Gas Pro_3

Crude Oil and Natural Gas Property Information - Schedule of Results of Operations from Crude Oil and Natural Gas Producing Activities (Detail) - USD ($) $ in Thousands	3 Months Ended				12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2018		Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Crude oil and natural gas sales					$ 4,678,722		$ 2,982,966	$ 2,026,958
Production expenses					(390,423)		(324,214)	(289,289)
Production taxes					(353,140)		(208,278)	(142,388)
Results of Operations, Transportation Costs	$ (49,000)	$ (46,000)	$ (47,300)	$ (49,300)	(191,587)		0	0
Exploration Expense					(7,642)		(12,393)	(16,972)
Depreciation, depletion, amortization and accretion					(1,839,241)		(1,652,180)	(1,679,485)
Property impairments					(125,210)		(237,370)	(237,292)
Income tax (provision) benefit (2)					(434,047)	[1]	504,475	126,794
Results from crude oil and natural gas producing activities					$ 1,337,432		$ 1,053,006	$ (211,674)
[1]	Income taxes reflect the application of a combined federal and state tax rate of 24.5% for 2018 and 38% for both 2017 and 2016 on pre-tax income and losses generated by operations in the United States. Additionally, the 2017 period includes a $713.7 million income tax benefit recognized upon the Company’s remeasurement of its deferred income tax assets and liabilities in response to the enactment of the Tax Cuts and Jobs Act in December 2017. See Note 9. Income Taxes for further discussion.

Crude Oil and Natural Gas Pro_4

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 31,579	$ 8,446	$ 5,008
Property Acquisition Costs - Unproved	329,586	220,875	149,962
Total property acquisition costs	361,165	229,321	154,970
Exploration Costs	81,015	123,461	182,355
Development Costs	2,478,327	1,695,954	767,148
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 2,920,507	$ 2,048,736	$ 1,104,473

Crude Oil and Natural Gas Pro_5

Crude Oil and Natural Gas Property Information - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ 25.8	$ 15.3	$ (9.6)

Crude Oil and Natural Gas Pro_6

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, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 24,060,625	$ 21,362,199
Unproved crude oil and natural gas properties	291,564	365,413
Total	24,352,189	21,727,612
Less accumulated depreciation, depletion and amortization	(10,680,870)	(8,971,935)
Net capitalized costs	$ 13,671,319	$ 12,755,677

Crude Oil and Natural Gas Pro_7

Crude Oil and Natural Gas Property Information - Schedule of Capitalized Exploratory Drilling Costs Pending Evaluation (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2018USD ($)Well	Dec. 31, 2017USD ($)Well	Dec. 31, 2016USD ($)Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 31,356	$ 34,852	$ 59,397
Additions to capitalized exploratory well costs pending determination of proved reserves	45,088	79,451	123,980
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(72,347)	(81,035)	(141,941)
Capitalized exploratory well costs charged to expense	(138)	(1,912)	(6,584)
Balance at December 31	$ 3,959	$ 31,356	$ 34,852
Number of wells | Well	16	37	54

Supplemental Crude Oil and Na_3

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2018MBoe	Dec. 31, 2018MMcf	Dec. 31, 2018MBbls	Dec. 31, 2018$ / Barrels	Dec. 31, 2017$ / bbl$ / McfMBoeMMcfMBbls	Dec. 31, 2016$ / bbl$ / McfMBoeMMcfMBbls
Reserve Quantities [Line Items]
Extensions, discoveries, and other additions		565,030				240,206	249,430
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					61.20	47.03	35.57
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				76,994		77,779	99,966
Extensions, discoveries and other additions | MBbls				253,066		129,895	97,587
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			1,153,555			25,390	63,057
Extensions, discoveries and other additions | MMcf			1,871,777			661,867	911,062
Weighted average price utilized in computation of future cash inflows					3.22	3	2.14
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			448,000	176,000
Extensions, discoveries, and other additions		251,000
SCOOP [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			733,000	64,000
Extensions, discoveries, and other additions		186,000
STACK [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			691,000	13,000
Extensions, discoveries, and other additions		128,000
Production Type | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		57				30
Production Type | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			216
Production Type | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				21
Price Driven | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		(26)				(42)	28
Price Driven | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			(31)
Price Driven | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				21
Other | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		4				5	12
Other | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			11
Other | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				2

Supplemental Crude Oil and Na_4

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Crude Oil and Natural Gas Reserves (Detail)	12 Months Ended
	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MBoe	1,522,365	1,330,995	1,274,864	1,225,811
Changes in Proved Reserves [Roll Forward]
Revisions of previous estimates | MBoe	(269,253)	(82,012)	(110,474)
Extensions, discoveries, and other additions | MBoe	565,030	240,206	249,430
Proved Developed and Undeveloped Reserve, Production (Energy) | MBoe	108,839	88,562	79,390
Sales of minerals in place, Total | MBoe	(8,011)	(15,197)	(10,513)
Purchases of minerals in place, Total | MBoe	12,443	1,696	0
Percent of proved crude oil reserve estimates prepared by external reserve engineers	98.00%	96.00%	99.00%
Natural Gas [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	4,140,281	3,789,818	3,151,786
Revisions of previous estimates | MMcf	(1,153,555)	(25,390)	(63,057)
Extensions, discoveries and other additions | MMcf	1,871,777	661,867	911,062
Production | MMcf	(284,730)	(228,159)	(195,240)
Sales of minerals in place | MMcf	(35,142)	(64,989)	(14,733)
Purchases of minerals in place | MMcf	52,983	7,134	0
Proved reserves at end of period | MMcf	4,591,614	4,140,281	3,789,818
Crude Oil [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls	640,949	643,228	700,514
Revisions of previous estimates | MBbls	(76,994)	(77,779)	(99,966)
Extensions, discoveries and other additions | MBbls	253,066	129,895	97,587
Production | MBbls	(61,384)	(50,536)	(46,850)
Sales of minerals in place | MBbls	(2,154)	(4,365)	(8,057)
Purchases of minerals in place | MBbls	3,613	506	0
Proved reserves at end of period | MBbls	757,096	640,949	643,228

Supplemental Crude Oil and Na_5

Supplemental Crude Oil and Natural Gas Information - Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities (Detail)	12 Months Ended
	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls	Dec. 31, 2015MBoeMMcf
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE) | MBoe	675,206	601,901	518,646
Proved Undeveloped Reserve (MBOE) | MBoe	847,159	729,094	756,218
Proved Developed and Undeveloped Reserve, Net (MBOE) | MBoe	1,522,365	1,330,995	1,274,864	1,225,811
Crude Oil [Member]
Reserve Quantities [Line Items]
Proved Developed Reserves (Volume) | MBbls	347,825	318,707	290,210
Proved Undeveloped Reserve (Volume) | MBbls	409,271	322,242	353,018
Proved Developed and Undeveloped Reserves, Net | MBbls	757,096	640,949	643,228
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	1,153,555	25,390	63,057
Proved Developed Reserves (Volume)	1,964,289	1,699,161	1,370,620
Proved Undeveloped Reserve (Volume)	2,627,325	2,441,120	2,419,198
Proved Developed and Undeveloped Reserves, Net	4,591,614	4,140,281	3,789,818	3,151,786
Change in development plans | Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	234	(89)	70
Change in development plans | Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	74
Change in development plans | Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	960
Price Driven | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	(26)	(42)	28
Price Driven | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	21
Price Driven | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	(31)
Production Type | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	57	30
Production Type | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	21
Production Type | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	216
Other | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBoe	4	5	12
Other | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	2
Other | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates	11

Supplemental Crude Oil and Na_6

Supplemental Crude Oil and Natural Gas Information - Standardized Measure of Discounted Future Net Cash Flows (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 61,510,432	$ 42,574,897	$ 31,008,587
Future production costs	(16,139,001)	(11,159,362)	(9,175,410)
Future development and abandonment costs	(9,706,114)	(6,487,097)	(6,452,647)
Future income taxes	(6,012,439)	(3,488,755)	(3,018,839)
Future net cash flows	29,652,878	21,439,683	12,361,691
10% annual discount for estimated timing of cash flows	(13,968,061)	(10,969,506)	(6,851,468)
Standardized measure of discounted future net cash flows	$ 15,684,817	$ 10,470,177	$ 5,510,223	$ 6,476,284

Supplemental Crude Oil and Na_7

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, 2018	Dec. 31, 2017	Dec. 31, 2016
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure of discounted future net cash flows at beginning of year	$ 10,470,177	$ 5,510,223	$ 6,476,284
Extensions, discoveries and improved recoveries, less related costs	5,162,635	1,462,629	786,587
Revisions of previous quantity estimates	(3,522,428)	(1,004,355)	(794,785)
Changes in estimated future development and abandonment costs	1,063,089	743,657	1,651,218
Sales of Minerals in Place	(9,192)	(41,077)	(90,390)
Net change in prices and production costs	4,224,473	3,808,116	(2,003,163)
Accretion of discount	1,183,347	665,507	798,597
Sales of crude oil and natural gas produced, net of production costs	(3,743,572)	(2,450,474)	(1,595,281)
Development costs incurred during the period	1,134,153	1,045,875	454,983
Change in timing of estimated future production and other	1,324,365	948,519	(538,665)
Change in income taxes	(1,602,230)	(218,443)	364,838
Net change	5,214,640	4,959,954	(966,061)
Standardized measure of discounted future net cash flows at end of year	$ 15,684,817	$ 10,470,177	$ 5,510,223

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, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Effect of Fourth Quarter Events [Line Items]
Estimated litigation liability, after tax																		$ 37,000
Basic eps litigation settlement									$ 0.10
Diluted eps estimated litigation settlement																		$ 0.10
Loss on extinguishment of debt	$ 0	[1]	$ 7,133	[1]	$ 0	[1]	$ 0	[1]									$ 7,133	$ 554	$ 26,055
Net income (loss)	199,121		314,169		242,464		233,946										989,700	789,447	(399,679)
Total revenues	1,149,294	[2]	1,282,151	[2]	1,137,113	[2]	1,141,028	[2]	$ 1,047,172	[2]	$ 726,743	[2]	$ 661,486	[2]	$ 685,427	[2]	4,709,586	3,120,828	1,980,273
Gain (loss) on derivative instruments, net	(19,394)	[2]	(2,025)	[2]	(12,685)	[2]	10,174	[2]	8,165	[2]	8,602	[2]	28,022	[2]	46,858	[2]	(23,930)	91,647	(71,859)
Property impairments	38,494	[3]	23,770	[3]	29,162	[3]	33,784	[3]	27,552	[3]	35,130	[3]	123,316	[3]	51,372	[3]	125,210	237,370	237,292
Litigation settlement									59,600	[4]	0	[4]	0	[4]	0	[4]	0	59,600	0
Gain (Loss) on Disposition of Property Plant Equipment	8,410	[5]	1,510	[5]	6,710	[5]	41	[5]	54,420	[5]	3,562	[5]	780	[5]	(3,638)	[5]	(16,671)	(55,124)	(304,489)
Income from operations	330,414		491,308		391,276		380,722		309,468		91,753		(29,041)		77,221		1,593,720	449,401	(287,534)
Tax benefit from US tax reform legislation																	0	(713,655)	0
Net income (loss) attributable to Continental Resources	$ 197,738		$ 314,169		$ 242,464		$ 233,946		$ 841,914		$ 10,621		$ (63,557)		$ 469		$ 988,317	$ 789,447	$ (399,679)
Net income per share: Basic	$ 0.53		$ 0.84		$ 0.65		$ 0.63		$ 2.27		$ 0.03		$ (0.17)		$ 0		$ 2.66	$ 2.13	$ (1.08)
Net income per share: Diluted	$ 0.53		$ 0.84		$ 0.65		$ 0.63		$ 2.25		$ 0.03		$ (0.17)		$ 0		$ 2.64	$ 2.11	$ (1.08)
[1]	See Note 7. Long-Term Debt for discussion of the loss recognized by the Company upon the partial redemption of its 2022 Notes in the 2018 third quarter.
[2]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income (loss) and this table of unaudited quarterly financial data. Natural gas 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. Additionally, beginning in 2018 certain transportation expenses are no longer netted within "Total revenues" as a result of the Company's January 1, 2018 prospective adoption of ASU 2016-08, which affects comparability of 2017 and 2018 revenues. Transportation expenses totaled $49.3 million, $47.3 million, $46.0 million, and $49.0 million for the first, second, third, and fourth quarters of 2018, respectively.
[3]	Property impairments have been shown separately to illustrate the impact on quarterly results 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.
[4]	Fourth quarter 2017 results include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies—Litigation, which resulted in an after-tax decrease in net income of $37.0 million ($0.10 per basic and diluted share).
[5]	Gains and losses on asset sales have been shown separately to illustrate the impact on quarterly results attributable to asset dispositions, which differ in significance from period to period and affect comparability. See Note 16. Property Dispositions for a discussion of notable dispositions.