Continental Resources Inc (CLR) 10-K 26 Feb 20 2019 FY Annual report Financial data

Document and Entity Information

Document and Entity Information Document - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2019	Feb. 07, 2020	Jun. 30, 2019
Entity Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2019
Document Transition Report	false
Entity File Number	001-32886
Entity Registrant Name	CONTINENTAL RESOURCES, INC.
Entity Central Index Key	0000732834
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Amendment Flag	false
Entity Incorporation, State or Country Code	OK
Entity Tax Identification Number	73-0767549
Entity Address, Address Line One	20 N. Broadway,
Entity Address, City or Town	Oklahoma City,
Entity Address, State or Province	OK
Entity Address, Postal Zip Code	73102
City Area Code	405
Local Phone Number	234-9000
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 3.5
Entity Common Stock, Shares Outstanding		371,541,200
NEW YORK STOCK EXCHANGE, INC. [Member]
Entity Information [Line Items]
Title of 12(b) Security	Common Stock, $0.01 par value
Trading Symbol	CLR
Security Exchange Name	NYSE

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 39,400	$ 282,749
Crude oil and natural gas sales	726,876	644,107
Joint interest and other, net	314,611	368,308
Derivative assets	0	15,612
Inventories	109,536	88,544
Prepaid expenses and other	16,592	13,041
Total current assets	1,207,015	1,412,361
Net property and equipment, based on successful efforts method of accounting	14,497,726	13,869,800
Operating lease right-of-use assets	9,128	0
Other noncurrent assets	14,038	15,786
Total assets	15,727,907	15,297,947
Current liabilities:
Accounts payable trade	629,264	717,723
Revenues and royalties payable	470,264	400,607
Accrued liabilities and other	230,368	266,819
Current portion of operating lease liability	3,695	0
Current portion of long-term debt	2,435	2,360
Total current liabilities	1,336,026	1,387,509
Long-term debt, net of current portion	5,324,079	5,765,989
Other noncurrent liabilities:
Deferred income tax liabilities, net	1,787,125	1,574,436
Asset retirement obligations, net of current portion	151,774	136,986
Operating lease liabilities, net of current portion	5,433	0
Other noncurrent liabilities	15,119	11,166
Total other noncurrent liabilities	1,959,451	1,722,588
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; 371,074,036 shares issued and outstanding at December 31, 2019; 376,021,575 shares issued and outstanding at December 31, 2018	3,711	3,760
Additional paid-in capital	1,274,732	1,434,823
Accumulated other comprehensive income	0	415
Retained earnings	5,463,224	4,706,135
Total shareholders’ equity attributable to Continental Resources	6,741,667	6,145,133
Noncontrolling interests	366,684	276,728
Total equity	7,108,351	6,421,861
Total liabilities and equity	$ 15,727,907	$ 15,297,947

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
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	371,074,036	376,021,575
Common stock, outstanding	371,074,036	376,021,575

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Crude oil and natural gas sales	$ 4,514,389	$ 4,678,722	$ 2,982,966
Gain (loss) on natural gas derivatives, net	49,083	(23,930)	91,647
Crude oil and natural gas service operations	68,475	54,794	46,215
Total revenues	4,631,947	4,709,586	3,120,828
Operating costs and expenses:
Production expenses	444,649	390,423	324,214
Production taxes	357,988	353,140	208,278
Transportation expenses	225,649	191,587	0
Exploration expenses	14,667	7,642	12,393
Crude oil and natural gas service operations	33,230	21,639	16,880
Depreciation, depletion, amortization and accretion	2,017,383	1,859,327	1,674,901
Property impairments	86,202	125,210	237,370
General and administrative expenses	195,302	183,569	191,706
Litigation settlement	0	0	59,600
Net gain on sale of assets and other	(535)	(16,671)	(53,915)
Total operating costs and expenses	3,374,535	3,115,866	2,671,427
Income from operations	1,257,412	1,593,720	449,401
Other income (expense):
Interest expense	(269,379)	(293,032)	(294,495)
Loss on extinguishment of debt	(4,584)	(7,133)	(554)
Other	3,713	3,247	1,715
Total other income (expense)	(270,250)	(296,918)	(293,334)
Income before income taxes	987,162	1,296,802	156,067
(Provision) benefit for income taxes	(212,689)	(307,102)	633,380
Net income (loss)	774,473	989,700	789,447
Net income (loss) attributable to noncontrolling interests	(1,168)	1,383	0
Net income (loss) attributable to Continental Resources	$ 775,641	$ 988,317	$ 789,447
Basic net income (loss) per share (in dollars per share)	$ 2.09	$ 2.66	$ 2.13
Diluted net income (loss) per share (in dollars per share)	$ 2.08	$ 2.64	$ 2.11
Foreign currency translation adjustments	$ 140	$ 108	$ 567
Release of cumulative translation adjustments	(555)	0	0
Other Comprehensive Income (Loss), Net of Tax	(415)	108	567
Comprehensive Income (Loss), Net of Tax, Consolidated	774,058	989,808	790,014
Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest	(1,168)	1,383	0
Comprehensive Income (Loss), Net of Tax, Attributable to Continental Resources	$ 775,226	$ 988,425	$ 790,014

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	Treasury Stock [Member]
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests							$ 0
Total equity	$ 4,301,996
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]
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, Tax	5,150				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		$ 3,752	1,409,326	307	3,717,818	5,131,203
Balance, shares at Dec. 31, 2017		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)
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
Net income (loss) attributable to Continental Resources	775,641				775,641	775,641
Net income (loss) attributable to noncontrolling interests	(1,168)						(1,168)
Net income (loss)	774,473
Dividends, Common Stock, Cash	(18,747)				(18,747)	(18,747)
Change in dividends payable	195				195	195
Treasury Stock, Value, Acquired, Cost Method	(190,239)					(190,239)		$ (190,239)
Treasury Stock, Shares, Retired		(5,646,553)
Treasury Stock, Retired, Cost Method, Amount	(190,200)	$ (56)	(190,183)					$ (190,239)
Other Comprehensive Income (Loss), Net of Tax	(415)			(415)		(415)
Equity transaction costs	0
Stock-based compensation	52,030		52,030			52,030
Contributions from noncontrolling interests	105,528						105,528
Distributions to noncontrolling interests	(14,404)						(14,404)
Restricted stock:
Issued	15	$ 15	0			15
Issued, shares		1,526,825
Repurchased and canceled	$ (21,943)	$ (5)	(21,938)			(21,943)
Repurchased and canceled, shares	(5,646,553)	(477,789)
Forfeited	$ (3)	$ (3)				(3)
Forfeited, shares		(350,022)
Balance at Dec. 31, 2019	$ 6,741,667	$ 3,711	$ 1,274,732	$ 0	$ 5,463,224	$ 6,741,667
Balance, shares at Dec. 31, 2019	371,074,036	371,074,036
Increase (Decrease) in Equity [Roll Forward]
Noncontrolling interests	$ 366,684						$ 366,684
Total equity	$ 7,108,351

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income (loss)	$ 774,473	$ 989,700	$ 789,447
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation, depletion, amortization and accretion	2,019,704	1,859,118	1,670,838
Property impairments	86,202	125,210	237,370
Non-cash (gain) loss on derivatives, net	15,612	(13,009)	(58,031)
Stock-based compensation	52,044	47,236	45,868
Tax benefit from US tax reform legislation	0	0	(713,655)
Provision for deferred income taxes from operations	212,689	314,878	88,056
Litigation settlement	0	0	59,600
Net gain on sale of assets and other	(535)	(16,671)	(55,124)
Loss on extinguishment of debt	4,584	7,133	554
Other, net	10,408	16,705	12,768
Changes in assets and liabilities:
Accounts receivable	(33,619)	94,765	(329,811)
Inventories	(21,204)	7,735	14,517
Other current assets	(4,459)	(3,539)	1,038
Accounts payable trade	(36,359)	9,274	137,339
Revenues and royalties payable	69,195	24,010	158,982
Accrued liabilities and other	(36,467)	(4,162)	21,368
Other noncurrent assets and liabilities	3,420	(2,375)	(2,018)
Net cash provided by operating activities	3,115,688	3,456,008	2,079,106
Cash flows from investing activities:
Exploration and development	(2,783,149)	(2,840,880)	(1,931,942)
Purchase of producing crude oil and natural gas properties	(51,558)	(31,579)	(8,446)
Purchase of other property and equipment	(25,983)	(42,171)	(12,810)
Proceeds from sale of assets	88,734	54,458	144,353
Net cash used in investing activities	(2,771,956)	(2,860,172)	(1,808,845)
Cash flows from financing activities:
Credit facility borrowings	1,216,000	2,024,000	1,302,000
Repayment of credit facility	(1,161,000)	(2,212,000)	(2,019,000)
Proceeds from issuance of Senior Notes	0	0	990,000
Redemption of Senior Notes	(500,000)	(400,000)	0
Premium on redemption of Senior Notes	(4,167)	(6,700)	0
Repayment of other debt	(2,352)	(2,286)	(502,214)
Debt issuance costs	0	(5,535)	(1,999)
Equity transaction costs	0	(4,838)	0
Contributions from noncontrolling interests	109,137	267,920	0
Distributions to noncontrolling interests	(14,164)	(604)	0
Payments for Repurchase of Common Stock	(190,239)	0	0
Repurchase of restricted stock for tax withholdings	(21,943)	(16,891)	(11,821)
Dividends paid on common stock	(18,380)	0	0
Net cash used in financing activities	(587,108)	(356,934)	(243,034)
Effect of exchange rate on cash and cash equivalents	27	(55)	32
Net change in cash and cash equivalents	(243,349)	238,847	27,259
Cash and cash equivalents at beginning of period	282,749	43,902	16,643
Cash and cash equivalents at end of period	$ 39,400	$ 282,749	$ 43,902

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
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 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 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 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, 2019 , the Company had cash deposits in excess of federally insured amounts of approximately $38.1 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's allowance for doubtful accounts, as accounted for under legacy U.S. GAAP in effect as of December 31, 2019, was determined 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 $2.4 million as of December 31, 2019 and 2018 , respectively, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets. The Company's method for determining its allowance for doubtful accounts was changed upon its January 1, 2020 adoption of ASU 2016-13 as subsequently discussed under the caption New accounting pronouncements not yet adopted at December 31, 2019—Credit Losses. 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, 2019 , sales to the Company’s largest purchaser accounted for approximately 13% 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 2019 . 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, 2019 and 2018 consisted of the following: December 31, In thousands 2019 2018 Tubular goods and equipment $ 14,880 $ 14,623 Crude oil 94,656 73,921 Total $ 109,536 $ 88,544 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 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. Sales of proved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. 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, 2017 through December 31, 2019 : In thousands 2019 2018 2017 Asset retirement obligations at January 1 $ 141,360 $ 114,406 $ 96,178 Accretion expense 8,443 6,985 5,886 Revisions (1) (1,762 ) 13,075 7,801 Plus: Additions for new assets 8,392 9,070 6,884 Less: Plugging costs and sold assets (2,760 ) (2,176 ) (2,343 ) Total asset retirement obligations at December 31 $ 153,673 $ 141,360 $ 114,406 Less: Current portion of asset retirement obligations at December 31 (2) 1,899 4,374 2,612 Non-current portion of asset retirement obligations at December 31 $ 151,774 $ 136,986 $ 111,794 (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, 2019 and 2018 , net property and equipment on the consolidated balance sheets included $55.8 million and $57.7 million , respectively, of net asset retirement costs. Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value. 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 $40.0 million and $51.2 million (net of accumulated amortization of $73.7 million and $62.5 million ) relating to its long-term debt at December 31, 2019 and 2018 , respectively. Unamortized capitalized costs associated with the Company’s Notes and note payable totaled $35.3 million and $45.1 million at December 31, 2019 and 2018 , 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 $4.7 million and $6.1 million at December 31, 2019 and 2018 , respectively, and are reflected in “Other noncurrent assets” on the consolidated balance sheets. For the years ended December 31, 2019 , 2018 and 2017 , the Company recognized amortization expense associated with capitalized debt issuance costs of $8.3 million , $9.3 million and $9.1 million , respectively, which are reflected in “Interest expense” on the consolidated statements of comprehensive income. Derivative instruments The Company recognizes its derivative instruments, if any, 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. Historically, the Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marked its derivative instruments to fair value and recognized the changes in fair value in the consolidated statements of comprehensive income under the caption “ Gain (loss) on natural gas derivatives, net .” Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2019 and 2018 . 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 period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. Earnings per share attributable to Continental Resources Basic net income per share is computed by dividing net income 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 per share attributable to the Company for the years ended December 31, 2019 , 2018 and 2017 . Year ended December 31, In thousands, except per share data 2019 2018 2017 Net income attributable to Continental Resources (numerator) (1) $ 775,641 $ 988,317 $ 789,447 Weighted average shares (denominator): Weighted average shares - basic 370,699 371,854 371,066 Non-vested restricted stock 1,839 2,984 2,702 Weighted average shares - diluted 372,538 374,838 373,768 Net income per share attributable to Continental Resources: (1) Basic $ 2.09 $ 2.66 $ 2.13 Diluted $ 2.08 $ 2.64 $ 2.11 (1) The Company sold its Canadian subsidiary and associated properties in 2019 which resulted in a decrease in income tax expense and corresponding increase in net income via the recognition of an income tax benefit of $16.9 million ( $0.05 per basic and diluted share). See Note 9. Income Taxes for further discussion. Additionally, results for 2017 include 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 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. Results for 2017 also include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share). Foreign currency translation In 2014, the Company initiated operations in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada are immaterial and were sold in the fourth quarter of 2019. See Note 16. Property Dispositions for further discussion. The Company 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 were 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. Adoption of new accounting pronouncement in 2019 On January 1, 2019 the Company adopted Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842) . See Note 10. Leases for discussion of the adoption impact and the applicable disclosures required by the new guidance. New accounting pronouncements not yet adopted at December 31, 2019 Credit losses – In June 2016, the Financial Accounting Standards Board ("FASB") issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the previously required incurred loss approach with a forward-looking expected credit loss model for accounts receivable and other financial instruments measured at amortized cost. The standard became effective for interim and annual periods beginning after December 15, 2019. The Company adopted the new standard on January 1, 2020 using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date, which had an immaterial impact. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial. Income taxes – In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 Supplemental cash flow information: Cash paid for interest $ 267,421 $ 270,927 $ 281,058 Cash paid for income taxes 229 — 2 Cash received for income tax refunds 107 7,893 257 Non-cash investing activities: Asset retirement obligation additions and revisions, net 6,630 22,145 14,685 As of December 31, 2019 and 2018 , the Company had $262.7 million and $317.5 million , respectively, of accrued capital expenditures included in “Net property and equipment” and “Accounts payable trade” in the consolidated balance sheets. As of December 31, 2019 and 2018 , the Company had $5.6 million and $9.3 million , respectively, of accrued contributions from noncontrolling interests included in "Receivables – Joint interest and other, net" and "Equity – Noncontrolling interests" in the condensed consolidated balance sheets. As of December 31, 2019 and 2018 , the Company had $1.5 million and $1.3 million , respectively, of accrued distributions to noncontrolling interests included in "Revenues and royalties payable" and "Equity – Noncontrolling interests" in the condensed consolidated balance sheets. On January 1, 2019 the Company adopted ASU 2016-02, Leases (Topic 842) , which resulted in the non-cash recognition of offsetting right-of-use assets and lease liabilities totaling approximately $19 million . See Note 10. Leases for additional information.

Net Property and Equipment

Net Property and Equipment	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment, Net [Abstract]
Net Property and Equipment	Net Property and Equipment Net property and equipment includes the following at December 31, 2019 and 2018 . December 31, In thousands 2019 2018 Proved crude oil and natural gas properties $ 26,611,429 $ 24,060,625 Unproved crude oil and natural gas properties 319,592 291,564 Service properties, equipment and other 336,439 324,758 Total property and equipment 27,267,460 24,676,947 Accumulated depreciation, depletion and amortization (12,769,734 ) (10,807,147 ) Net property and equipment $ 14,497,726 $ 13,869,800

Accrued Liabilities and Other

Accrued Liabilities and Other	12 Months Ended
	Dec. 31, 2019
Accrued Liabilities and Other Liabilities [Abstract]
Accrued Liabilities and Other	Accrued Liabilities and Other Accrued liabilities and other includes the following at December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Prepaid advances from joint interest owners $ 50,021 $ 53,674 Accrued compensation 61,483 69,338 Accrued production taxes, ad valorem taxes and other non-income taxes 59,057 52,105 Accrued interest 56,953 64,483 Accrued litigation settlement (see Note 11) — 19,753 Current portion of asset retirement obligations 1,899 4,374 Other 955 3,092 Accrued liabilities and other $ 230,368 $ 266,819

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments Natural gas derivatives From time to time the Company has entered into natural gas swap and collar derivative contracts to economically hedge against the variability in cash flows associated with future sales of natural gas production. At December 31, 2019 , the Company had no outstanding commodity derivative contracts. The Company recognizes its derivative instruments, if any, on the balance sheet as either assets or liabilities measured at fair value. 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, volatility, the risk-free interest rate, and the time to expiration. The calculation of the fair value of collars requires the use of an option-pricing model. See Note 6. Fair Value Measurements . 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. The Company's natural gas derivatives were settled based upon reported NYMEX Henry Hub settlement prices. Non-cash gains and losses below represent the change in fair value of derivative instruments which continued to be held at period end, if any, 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 2019 2018 2017 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 58,836 $ (36,939 ) $ 40,095 Natural gas collars 5,859 — (10,539 ) Cash received (paid) on derivatives, net 64,695 (36,939 ) 29,556 Non-cash gain (loss) on derivatives: Natural gas fixed price swaps (10,130 ) 7,527 18,960 Natural gas collars (5,482 ) 5,482 43,131 Non-cash gain (loss) on derivatives, net (15,612 ) 13,009 62,091 Gain (loss) on natural gas derivatives, net $ 49,083 $ (23,930 ) $ 91,647 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 2019 2018 Commodity derivative assets: Gross amounts of recognized assets $ — $ 16,789 Gross amounts offset on balance sheet — (1,177 ) Net amounts of assets on balance sheet — 15,612 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 2019 2018 Derivative assets $ — $ 15,612 Noncurrent derivative assets — — Net amounts of assets on balance sheet — 15,612 Derivative liabilities — — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — — Total derivative assets, net $ — $ 15,612

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2019
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, if any, 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 table summarizes the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2018 . The Company had no outstanding commodity derivative instruments at December 31, 2019 . 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 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, 2019 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 2024 (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, 2019 , 2018 , and 2017 , the Company determined the carrying amounts of certain proved properties were not recoverable from future cash flows, and therefore, were impaired. Such impairments totaled $3.7 million and $18.0 million for 2019 and 2018 , respectively, 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 . Certain unproved crude oil and natural gas properties were impaired during the years ended December 31, 2019 , 2018 , and 2017 , 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. Year ended December 31, In thousands 2019 2018 2017 Proved property impairments $ 3,745 $ 18,037 $ 82,340 Unproved property impairments 82,457 107,173 155,030 Total $ 86,202 $ 125,210 $ 237,370 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, 2019 December 31, 2018 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Revolving credit facility $ 55,000 $ 55,000 $ — $ — Note payable 5,351 5,400 7,700 7,700 5% Senior Notes due 2022 1,099,165 1,108,700 1,598,404 1,590,900 4.5% Senior Notes due 2023 1,491,339 1,571,400 1,488,960 1,476,300 3.8% Senior Notes due 2024 994,310 1,034,200 993,151 947,200 4.375% Senior Notes due 2028 989,661 1,063,700 988,617 942,800 4.9% Senior Notes due 2044 691,688 742,000 691,517 618,800 Total debt $ 5,326,514 $ 5,580,400 $ 5,768,349 $ 5,583,700 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, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $33.9 million and $39.4 million at December 31, 2019 and 2018 , respectively, consists of the following. December 31, In thousands 2019 2018 Revolving credit facility $ 55,000 $ — Note payable 5,351 7,700 5% Senior Notes due 2022 1,099,165 1,598,404 4.5% Senior Notes due 2023 1,491,339 1,488,960 3.8% Senior Notes due 2024 994,310 993,151 4.375% Senior Notes due 2028 989,661 988,617 4.9% Senior Notes due 2044 691,688 691,517 Total debt 5,326,514 5,768,349 Less: Current portion of long-term debt 2,435 2,360 Long-term debt, net of current portion $ 5,324,079 $ 5,765,989 Revolving credit facility The Company has an unsecured credit facility, maturing in April 2023, with aggregate lender commitments totaling $1.5 billion . The Company had $55.0 million of outstanding borrowings on its credit facility at December 31, 2019 . Credit facility borrowings 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 weighted-average interest rate on outstanding credit facility borrowings at December 31, 2019 was 3.3% . The Company had approximately $1.45 billion of borrowing availability on its credit facility at December 31, 2019 and incurs commitment fees based on currently assigned credit ratings of 0.20% per annum on the daily average amount of unused borrowing availability. The credit facility contains certain restrictive covenants including a requirement that the Company maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (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, 2019 . 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, 2019 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $1,100,000 $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, 2019 . 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. Partial redemptions of senior notes 2019 In September 2019, the Company redeemed $500 million of its previously outstanding $1.6 billion of 5% Senior Notes due 2022. The redemption price was equal to 100.833% of the principal amount called for redemption plus accrued and unpaid interest to the redemption date. The aggregate of the principal amount, redemption premium, and accrued interest paid upon redemption was $516.5 million . The Company recorded a pre-tax loss on extinguishment of debt related to the redemption of $4.6 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. 2018 In August 2018, the Company redeemed $400 million of its original 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. The aggregate of the principal amount, redemption premium, and accrued interest paid upon redemption 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. 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, 2019 .

Revenues Revenues

Revenues Revenues	12 Months Ended
	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	Revenues 2018 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. Subsequently, the FASB issued 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. The Company adopted the new guidance on January 1, 2018 using a modified retrospective transition approach to all applicable contracts at the date of initial application, whereby the standard was applied for periods commencing on January 1, 2018 and results prior to 2018 were not 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 beginning on January 1, 2018 result 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. 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 are presented separately from transportation expenses, 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 $192.0 million and $162.3 million for the years ended December 31, 2019 and 2018 , respectively. 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. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary settlement, but does not currently take NGL volumes. 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 $33.7 million and $29.3 million for the years ended December 31, 2019 and 2018 , respectively. 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 periods presented. Year ended December 31, 2019 2018 In thousands North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 2,365,574 $ 786,652 $ 3,152,226 $ 2,330,711 $ 603,070 $ 2,933,781 Non-operated properties 727,068 50,700 777,768 790,435 68,378 858,813 Total crude oil revenues 3,092,642 837,352 3,929,994 3,121,146 671,448 3,792,594 Natural gas revenues: Operated properties 109,668 411,464 521,132 214,741 547,247 761,988 Non-operated properties 25,188 38,075 63,263 60,738 63,402 124,140 Total natural gas revenues 134,856 449,539 584,395 275,479 610,649 886,128 Crude oil and natural gas sales $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 3,396,625 $ 1,282,097 $ 4,678,722 Timing of revenue recognition Goods transferred at a point in time $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 3,396,625 $ 1,282,097 $ 4,678,722 Goods transferred over time — — — — — — $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 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. Judgment may be required in determining the point in time when control transfers 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, 2019 are short-term in nature with contract terms of one year or less. 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 the Company’s 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 years ended December 31, 2019 and 2018 related to performance obligations satisfied in prior reporting periods were not material.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
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 or 2019. The items comprising the Company's provision (benefit) for income taxes are as follows for the periods presented: Year ended December 31, In thousands 2019 2018 2017 Current income tax provision (benefit): United States federal (1) $ — $ (7,781 ) $ (7,781 ) Various states — 5 — Total current income tax (benefit) — (7,776 ) (7,781 ) Deferred income tax provision (benefit): United States federal - taxation on operations 191,328 282,947 81,054 United States federal - effect of US tax reform — — (713,655 ) Various states 21,361 31,931 7,002 Total deferred income tax provision (benefit) 212,689 314,878 (625,599 ) Provision (benefit) for income taxes $ 212,689 $ 307,102 $ (633,380 ) Effective tax rate 21.5 % 23.7 % (405.8 %) (1) The current federal income tax benefits for 2017 and 2018 represent alternative minimum tax refunds. The Company's effective tax rate differs from the United States federal statutory tax rate due to the effect of state income taxes and other tax items as reflected in the table below. Year ended December 31, In thousands, except rates 2019 2018 2017 Income before income taxes $ 987,162 $ 1,296,802 $ 156,067 U.S. federal statutory tax rate 21.0 % 21.0 % 35.0 % Expected income tax provision based on US statutory tax rate 207,304 272,328 54,623 Items impacting the effective tax rate: State income taxes, net of federal benefit 31,967 45,920 4,682 Effect of US tax reform legislation — — (713,655 ) Tax benefit (deficiency) from stock-based compensation (7,971 ) (259 ) 3,932 Non-deductible compensation 8,282 2,932 13,813 Sale of Canadian subsidiary and assets (16,860 ) — — Other, net (10,033 ) (13,819 ) 3,225 Provision (benefit) for income taxes $ 212,689 $ 307,102 $ (633,380 ) Effective tax rate 21.5 % 23.7 % (405.8 %) The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are reflected in the table below. December 31, In thousands 2019 2018 Deferred tax assets United States net operating loss carryforwards $ 550,086 $ 549,166 Canadian net operating loss carryforwards — 19,633 Equity compensation 13,157 13,122 Other 18,466 13,622 Total deferred tax assets 581,709 595,543 Canadian valuation allowance — (19,633 ) Total deferred tax assets, net of valuation allowance 581,709 575,910 Deferred tax liabilities Property and equipment (2,367,137 ) (2,144,767 ) Other (1,697 ) (5,579 ) Total deferred tax liabilities (2,368,834 ) (2,150,346 ) Deferred income tax liabilities, net $ (1,787,125 ) $ (1,574,436 ) As of December 31, 2019 , the Company had federal and state net operating loss carryforwards of $1.9 billion and $3.3 billion , respectively. The federal net operating loss carryforward will begin expiring in 2035 . The Company’s net operating loss carryforward in Oklahoma totaled $2.3 billion at December 31, 2019 , which will begin to expire in 2028. The Company’s net operating loss carryforward in North Dakota totaled $872 million at December 31, 2019 , 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 2016. In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties. The Company recognized immaterial valuation allowances for the years ended December 31, 2018 and 2017 against deferred tax assets associated with operating loss carryforwards generated by its Canadian subsidiary for which the Company did not expect to realize a benefit. Prior to the sale the cumulative valuation allowance recorded was $19.6 million . In conjunction with the sale, the deferred tax assets, deferred tax liabilities, and cumulative valuation allowance related to the Canadian subsidiary were removed, and an income tax benefit of $16.9 million was recorded related to the resulting capital loss on the sale of the stock.

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Operating Leases [Text Block]	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 twelve 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 right-of-use assets and lease liabilities recognized by the Company on the January 1, 2019 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. No cumulative-effect adjustment to retained earnings was recognized upon adoption of the new standard. 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 ASC Topic 842 to leases with durations of twelve months or less and has elected to use hindsight in determining the lease term for all leases. The Company's leasing activities as a lessor are negligible. Presented below are disclosures required by the new lease standard. The amounts disclosed herein primarily represent costs associated with properties operated by the Company that are presented on a gross basis and do not reflect the Company's net proportionate share of such amounts. A portion of these costs have been or will be billed to other working interest owners. Once paid, the Company's share of these costs are included in property and equipment, production expenses, or general and administrative expenses, as applicable. The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $9.1 million as of December 31, 2019 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. In thousands Amount Drilling rig commitments $ 3,154 Surface use agreements 4,487 Field equipment 1,164 Other 323 Total $ 9,128 Drilling rig commitments reflected above represent minimum payment obligations expected to be incurred on enforceable commitments with durations in excess of one year at the inception of the lease. Minimum future commitments by year for the Company's operating leases as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet. In thousands Amount 2020 $ 3,999 2021 750 2022 734 2023 667 2024 411 Thereafter 5,755 Total operating lease liabilities, at undiscounted value $ 12,316 Less: Imputed interest (3,188 ) Total operating lease liabilities, at discounted present value $ 9,128 Less: Current portion of operating lease liabilities (3,695 ) Operating lease liabilities, net of current portion $ 5,433 Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. In thousands, except weighted average data Year ended December 31, 2019 Lease costs: Operating lease costs $ 11,130 Variable lease costs 11,930 Short-term lease costs 176,586 Total lease costs $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,208 Operating cash flows from operating leases included in lease liabilities 804 Weighted average remaining lease term as of December 31, 2019 (in years) 11.5 Weighted average discount rate as of December 31, 2019 4.9 % Prior to the January 1, 2019 adoption of ASU 2016-02, the Company’s operating lease obligations, as defined and accounted for under legacy U.S. GAAP in effect as of December 31, 2018, primarily represented leases for surface use agreements, office buildings and equipment, communication towers, and field equipment. Lease payments associated with legacy operating leases for the years ended December 31, 2018 and 2017 were $2.0 million and $1.9 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 legacy 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 were not required to be recognized on the Company's balance sheet under legacy U.S. GAAP in effect as of December 31, 2018. In thousands Total amount as of December 31, 2018 2019 $ 1,535 2020 1,042 2021 833 2022 805 2023 745 Thereafter 6,795 Total obligations as of December 31, 2018 $ 11,755
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Minimum future commitments by year for the Company's operating leases as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet. In thousands Amount 2020 $ 3,999 2021 750 2022 734 2023 667 2024 411 Thereafter 5,755 Total operating lease liabilities, at undiscounted value $ 12,316 Less: Imputed interest (3,188 ) Total operating lease liabilities, at discounted present value $ 9,128 Less: Current portion of operating lease liabilities (3,695 ) Operating lease liabilities, net of current portion $ 5,433
Lessee, Operating Lease, Disclosure [Table Text Block]	The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $9.1 million as of December 31, 2019 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. In thousands Amount Drilling rig commitments $ 3,154 Surface use agreements 4,487 Field equipment 1,164 Other 323 Total $ 9,128
Lease, Cost [Table Text Block]	Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. In thousands, except weighted average data Year ended December 31, 2019 Lease costs: Operating lease costs $ 11,130 Variable lease costs 11,930 Short-term lease costs 176,586 Total lease costs $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,208 Operating cash flows from operating leases included in lease liabilities 804 Weighted average remaining lease term as of December 31, 2019 (in years) 11.5 Weighted average discount rate as of December 31, 2019 4.9 %
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	At December 31, 2018, the minimum future rental commitments under legacy 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 were not required to be recognized on the Company's balance sheet under legacy U.S. GAAP in effect as of December 31, 2018. In thousands Total amount as of December 31, 2018 2019 $ 1,535 2020 1,042 2021 833 2022 805 2023 745 Thereafter 6,795 Total obligations as of December 31, 2018 $ 11,755

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2019
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, 2019 . Drilling commitments – As of December 31, 2019 , the Company has drilling rig contracts with various terms extending to November 2020 to ensure rig availability in its key operating areas. Future operating day-rate commitments as of December 31, 2019 total approximately $64 million , all of which will be incurred in 2020. A portion of these future costs will be borne by other interest owners. Such future commitments include minimum payment obligations with a discounted present value totaling $3.2 million that are required to be recognized on the Company’s balance sheet at December 31, 2019 in accordance with ASC Topic 842 as discussed in Note 10. Leases . Other lease commitments – The Company has various other lease commitments primarily associated with surface use agreements and field equipment. See Note 10. Leases for additional information. Transportation, gathering, and processing commitments – The Company has entered into transportation, gathering, 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 2031, require the Company to pay per-unit transportation, gathering, or processing charges regardless of the amount of capacity used. Future commitments remaining as of December 31, 2019 under the arrangements amount to approximately $2.20 billion , of which $291 million is expected to be incurred in 2020, $332 million in 2021, $330 million in 2022, $331 million in 2023, $298 million in 2024, and $615 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 under ASC Topic 842 and are not recognized on the Company’s balance sheet. 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. Due to the uncertainty of and burdens of litigation, in February 2018 the Company reached a settlement in connection with this matter, which was subsequently approved by the District Court of Garfield County, Oklahoma in June 2018. 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 which, after making partial settlement payments in 2018, was reduced to $19.8 million at December 31, 2018. The Company has now satisfied substantially all of its monetary obligations under the settlement. 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. As of December 31, 2019 and 2018 , the Company had recorded a liability in the consolidated balance sheets under the caption “Other noncurrent liabilities” of $8.7 million and $4.7 million , respectively, for various matters, none of which are believed to be individually significant. Environmental risk – Due to the nature of the crude oil and natural gas business, the Company is exposed to possible environmental risks. The Company is not aware of any material environmental issues or claims.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2019
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 $0.4 million , $0.5 million , and $0.5 million and received payments from these affiliates of $0.3 million , $0.2 million , and $0.3 million during the years ended December 31, 2019 , 2018 , and 2017 , respectively, relating to the operations of the respective properties. At December 31, 2019 and 2018 , approximately $127,000 and $67,000 , respectively, was due from these affiliates relating to these transactions, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets. At December 31, 2019 and 2018 , approximately $35,000 and $41,000 , respectively, was due to these affiliates relating to these transactions, which is included in “Revenues and royalties payable” on the consolidated balance sheets. 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. For usage during 2019 , 2018 , and 2017 , the Company charged affiliates approximately $17,600 , $12,900 , and $19,400 , respectively, for use of its corporate aircraft crews, fuel, and reimbursement of expenses and received approximately $18,900 , $14,400 , and $18,600 from affiliates in 2019 , 2018 , and 2017 , respectively, in connection with such items. The Company was charged approximately $303,000 , $598,000 , and $460,000 , respectively, by affiliates for use of their aircraft and reimbursement of expenses during 2019 , 2018 , and 2017 and paid $426,000 , $529,000 , and $368,000 to the affiliates in 2019 , 2018 , and 2017 , respectively. At December 31, 2019 and 2018 , approximately $1,400 and $2,700 , respectively, was due from an affiliate relating to these transactions, which is included in “Receivables — Joint interest and other, net” on the consolidated balance sheets. At December 31, 2019 and 2018 , approximately $38,000 and $161,000

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [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, as amended (“2013 Plan”). The Company’s associated compensation expense, which is included in the caption “General and administrative expenses” in the consolidated statements of comprehensive income, was $52.0 million , $47.2 million , and $45.9 million for the years ended December 31, 2019 , 2018 and 2017 , respectively. On March 26, 2019, the Company amended and restated its 2013 Plan and reserved 12,983,543 shares of common stock that may be issued pursuant to the amended plan. The 2013 Plan allows previously issued shares to be reissued if such shares are subsequently forfeited after issuance. As of December 31, 2019 , the Company had 13,036,804 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 under the Company's dividend payment program discussed in Note 14. Shareholders' Equity Attributable to Continental Resources , subject to forfeiture. Restricted stock grants generally vest over periods ranging from 1 to 3 years. A summary of changes in non-vested restricted shares from December 31, 2016 to December 31, 2019 is presented below. Number of Weighted 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 Granted 1,526,825 43.21 Vested (1,737,304 ) 24.19 Forfeited (350,022 ) 47.13 Non-vested restricted shares at December 31, 2019 3,461,908 $ 46.82 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 2019 , 2018 , and 2017 was approximately $79.7 million , $61.0 million , and $39.8 million , respectively. As of December 31, 2019 , there was approximately $66 million of unrecognized compensation expense related to non-vested restricted stock. This expense is expected to be recognized over a weighted average period of 1.2 years.

Shareholders' Equity Attributab

Shareholders' Equity Attributable to Continental Resources (Notes)	12 Months Ended
	Dec. 31, 2019
Shareholders' Equity Attributable to Continental Resources [Abstract]
Shareholders' Equity Attributable to Continental Resources	Shareholders' Equity Attributable to Continental Resources Share repurchase program In May 2019 the Company's Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of the Company's common stock beginning in June 2019. As of December 31, 2019 , the Company had repurchased and retired 5,646,553 shares under the program at an aggregate cost of $190.2 million . Under the program, the Company may repurchase shares from time to time at management's discretion in accordance with applicable securities laws, including through open market transactions, privately negotiated transactions or any combination thereof. In addition, shares may also be repurchased pursuant to a trading plan meeting the requirements of Rule 10b5-1 under the Securities Exchange Act of 1934. The timing and amount of repurchases are subject to market conditions. The share repurchase program does not require the Company to repurchase a specific number of shares and may be modified, suspended, or terminated by the Board of Directors at any time. Dividend declaration In May 2019 the Company's Board of Directors approved the initiation of a dividend payment program and on June 3, 2019 the Company announced its first quarterly cash dividend of $0.05 per share on its outstanding common stock, which amounted to $18.4 million and was paid on November 21, 2019 to shareholders of record on November 7, 2019. Subsequent to December 31, 2019 , on January 27 , 2020 the Company declared a quarterly cash dividend of $0.05 per share on its outstanding common stock, which amounted to $18.4 million and was paid on February 21 , 2020 to shareholders of record as of February 7 , 2020. Accumulated other comprehensive income Adjustments resulting from the process of translating foreign functional currency financial statements into U.S. dollars are included in “Accumulated other comprehensive income” 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. The following table summarizes the change in accumulated other comprehensive income (loss) for the years ended December 31, 2019 , 2018 , and 2017 : Year ended December 31, In thousands 2019 2018 2017 Beginning accumulated other comprehensive income (loss), net of tax $ 415 $ 307 $ (260 ) Foreign currency translation adjustments 140 108 567 Release of cumulative translation adjustments (1) (555 ) — — Income taxes (2) — — — Other comprehensive income (loss), net of tax (415 ) 108 567 Ending accumulated other comprehensive income, net of tax $ — $ 415 $ 307 (1) In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 16. Property Dispositions for further information. (2) A valuation allowance had 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, 2019
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 minerals subsidiary named The Mineral Resources Company II, LLC (“TMRC II”). At closing in October 2018, 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. Under the arrangement, 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 and manages its operations. Accordingly, Continental consolidates the financial results of the entity and presents the portion of TMRC II’s results attributable to Franco-Nevada as a noncontrolling interest in its consolidated financial statements. In 2018 and 2019 Franco-Nevada made additional capital contributions to, and received revenue distributions from, TMRC II and the portion of Continental’s consolidated net assets attributable to Franco-Nevada totaled $356.9 million and $266.8 million at December 31, 2019 and 2018 , respectively. In 2018, Continental incurred $4.8 million of costs associated with the above 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 an entity named SFPG, LLC (“SFPG”). Continental holds a controlling financial interest in SFPG and manages its operations. Accordingly, Continental consolidates the financial results of the entity and includes 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 $9.8 million and $9.9 million at December 31, 2019 and 2018 , respectively.

Property Dispositions

Property Dispositions	12 Months Ended
	Dec. 31, 2019
Extractive Industries [Abstract]
Property Dispositions	Property Dispositions 2019 In November 2019, the Company sold its Canadian subsidiary and related operations for cash proceeds of $1.7 million and recognized a $1.0 million pre-tax gain on the sale. The Company designated the Canadian dollar as the functional currency for its Canadian operations and, with the sale of the Canadian subsidiary, $0.5 million of cumulative translation adjustments included in "Accumulated other comprehensive income" on the consolidated balance sheets were released and included in the determination of the gain on sale. The disposed subsidiary and properties represented an immaterial portion of the Company’s assets and operating results. In July 2019, the Company sold certain water gathering, recycling, and disposal assets in the STACK play for proceeds of $85.3 million , with no gain or loss recognized. The sale represented an immaterial portion of the Company’s assets and operating results. 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

Crude Oil and Natural Gas Prope

Crude Oil and Natural Gas Property Information	12 Months Ended
	Dec. 31, 2019
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 operations in Canada which were sold in the fourth quarter of 2019. The Company's Canadian operations have not had a material impact on historical 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 not material relative to the Company's consolidated results 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, 2019 , 2018 and 2017 . Year ended December 31, In thousands 2019 2018 2017 Crude oil and natural gas sales (1) $ 4,514,389 $ 4,678,722 $ 2,982,966 Production expenses (444,649 ) (390,423 ) (324,214 ) Production taxes (357,988 ) (353,140 ) (208,278 ) Transportation expenses (1) (225,649 ) (191,587 ) — Exploration expenses (14,667 ) (7,642 ) (12,393 ) Depreciation, depletion, amortization and accretion (1,997,854 ) (1,839,241 ) (1,652,180 ) Property impairments (86,202 ) (125,210 ) (237,370 ) Income tax (provision) benefit (2) (323,025 ) (434,047 ) 504,475 Results from crude oil and natural gas producing activities $ 1,064,355 $ 1,337,432 $ 1,053,006 (1) For 2019 and 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 rules were prospectively applied beginning January 1, 2018 and prior period results were not 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 2019 and 2018 and a 38% combined tax rate for 2017 on pre-tax income generated by operations in the United States. Additionally, the 2019 period includes the $16.9 million income tax benefit recognized upon the Company's sale of its Canadian operations during the year. Further, the 2017 period includes the $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. 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, 2019 , 2018 and 2017 are presented below: Year ended December 31, In thousands 2019 2018 2017 Property acquisition costs: Proved $ 51,558 $ 31,579 $ 8,446 Unproved 312,680 329,586 220,875 Total property acquisition costs 364,238 361,165 229,321 Exploration Costs 50,143 81,015 123,461 Development Costs 2,388,582 2,478,327 1,695,954 Total $ 2,802,963 $ 2,920,507 $ 2,048,736 Costs incurred above include asset retirement costs and revisions thereto of $6.7 million , $25.8 million and $15.3 million for the years ended December 31, 2019 , 2018 and 2017 , 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, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Proved crude oil and natural gas properties $ 26,611,429 $ 24,060,625 Unproved crude oil and natural gas properties 319,592 291,564 Total 26,931,021 24,352,189 Less accumulated depreciation, depletion and amortization (12,635,247 ) (10,680,870 ) Net capitalized costs $ 14,295,774 $ 13,671,319 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 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 2019 2018 2017 Balance at January 1 $ 3,959 $ 31,356 $ 34,852 Additions to capitalized exploratory well costs pending determination of proved reserves 28,280 45,088 79,451 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (23,200 ) (72,347 ) (81,035 ) Capitalized exploratory well costs charged to expense (2,782 ) (138 ) (1,912 ) Balance at December 31 $ 6,257 $ 3,959 $ 31,356 Number of gross wells 11 16 37 As of December 31, 2019 , 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, 2019
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 91% , 98% , and 96% of the Company's total proved reserves as of December 31, 2019 , 2018 , and 2017 , 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 for the periods presented. Proved reserves attributable to noncontrolling interests are not material relative to the Company's consolidated reserves 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, 2019 , 2018 and 2017 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, 2019 , 2018 and 2017 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, 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 (88,307 ) (363,239 ) (148,848 ) Extensions, discoveries and other additions 162,710 1,213,947 365,034 Production (72,267 ) (311,865 ) (124,244 ) Sales of minerals in place (803 ) (6,224 ) (1,840 ) Purchases of minerals in place 1,758 30,238 6,798 Proved reserves as of December 31, 2019 760,187 5,154,471 1,619,265 Revisions of previous estimates. Revisions for 2019 are comprised of (i) the removal of 17 MMBo and 108 Bcf (totaling 35 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 38 MMBo and 278 Bcf (totaling 85 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, (iii) downward price revisions of 24 MMBo and 118 Bcf (totaling 43 MMBoe) due to a decrease in average crude oil and natural gas prices in 2019 compared to 2018, and (iv) net downward revisions for oil reserves of 9 MMBo and net upward revisions for natural gas reserves of 139 Bcf (netting to 14 MMBoe of upward revisions) due to changes in ownership interests, operating costs, anticipated production, and other factors. 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 changes in development plans, (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, 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. 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 2019, proved reserve additions in the Bakken totaled 113 MMBo and 283 Bcf (totaling 160 MMBoe) and reserve additions in SCOOP totaled 47 MMBo and 830 Bcf (totaling 186 MMBoe). Additionally, 2019 proved reserve additions in STACK totaled 2 MMBo and 101 Bcf (totaling 19 MMBoe). Sales of minerals in place. See Note 16. Property Dispositions for a discussion of notable dispositions in 2019 , 2018 and 2017 , 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 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, 2019 , 2018 and 2017 : December 31, 2019 2018 2017 Proved Developed Reserves Crude oil (MBbl) 336,405 347,825 318,707 Natural Gas (MMcf) 2,226,117 1,964,289 1,699,161 Total (MBoe) 707,424 675,206 601,901 Proved Undeveloped Reserves Crude oil (MBbl) 423,782 409,271 322,242 Natural Gas (MMcf) 2,928,354 2,627,325 2,441,120 Total (MBoe) 911,841 847,159 729,094 Total Proved Reserves Crude oil (MBbl) 760,187 757,096 640,949 Natural Gas (MMcf) 5,154,471 4,591,614 4,140,281 Total (MBoe) 1,619,265 1,522,365 1,330,995 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, 2019 , 2018 and 2017 . Discounted future net cash flows attributable to noncontrolling interests are not material relative to the Company's consolidated amounts and are not separately presented below. December 31, In thousands 2019 2018 2017 Future cash inflows $ 49,893,470 $ 61,510,432 $ 42,574,897 Future production costs (15,309,672 ) (16,139,001 ) (11,159,362 ) Future development and abandonment costs (10,033,887 ) (9,706,114 ) (6,487,097 ) Future income taxes (1) (3,351,657 ) (6,012,439 ) (3,488,755 ) Future net cash flows 21,198,254 29,652,878 21,439,683 10% annual discount for estimated timing of cash flows (10,736,613 ) (13,968,061 ) (10,969,506 ) Standardized measure of discounted future net cash flows $ 10,461,641 $ 15,684,817 $ 10,470,177 (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, 2019, 2018, and 2017. The weighted average crude oil price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $51.95 , $61.20 , and $47.03 per barrel at December 31, 2019 , 2018 and 2017 , respectively. The weighted average natural gas price (adjusted for location and quality differentials) utilized in the computation of future cash inflows was $2.02 , $3.22 , and $3.00 per Mcf at December 31, 2019 , 2018 and 2017 , 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 2019 2018 2017 Standardized measure of discounted future net cash flows at January 1 $ 15,684,817 $ 10,470,177 $ 5,510,223 Extensions, discoveries and improved recoveries, less related costs 1,649,322 5,162,635 1,462,629 Revisions of previous quantity estimates (1,564,503 ) (3,522,428 ) (1,004,355 ) Changes in estimated future development and abandonment costs 1,401,513 1,063,089 743,657 Purchases (sales) of minerals in place, net 49,330 (9,192 ) (41,077 ) Net change in prices and production costs (6,591,347 ) 4,224,473 3,808,116 Accretion of discount 1,865,034 1,183,347 665,507 Sales of crude oil and natural gas produced, net of production costs (3,486,103 ) (3,743,572 ) (2,450,474 ) Development costs incurred during the period 1,557,121 1,134,153 1,045,875 Change in timing of estimated future production and other (1,690,779 ) 1,324,365 948,519 Change in income taxes 1,587,236 (1,602,230 ) (218,443 ) Net change (5,223,176 ) 5,214,640 4,959,954 Standardized measure of discounted future net cash flows at December 31 $ 10,461,641 $ 15,684,817 $ 10,470,177

Quarterly Financial Data (Unaud

Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Quarterly Financial Data (Unaudited)	Quarterly Financial Data (Unaudited) The Company’s unaudited quarterly financial data for 2019 and 2018 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2019 Total revenues (1) $ 1,124,234 $ 1,208,382 $ 1,104,197 $ 1,195,134 Gain (loss) on natural gas derivatives, net (1) $ (1,124 ) $ 53,448 $ 1,195 $ (4,436 ) Property impairments (2) $ 25,316 $ 21,339 $ 20,199 $ 19,348 Gain (loss) on sale of assets, net (3) $ 252 $ (364 ) $ (535 ) $ 1,182 Income from operations $ 304,965 $ 379,847 $ 278,724 $ 293,876 Loss on extinguishment of debt (4) $ — $ — $ (4,584 ) $ — Net income (5) $ 186,493 $ 236,450 $ 157,422 $ 194,108 Net income attributable to Continental Resources (5) $ 186,976 $ 236,557 $ 158,162 $ 193,946 Net income per share attributable to Continental Resources: (5) Basic $ 0.50 $ 0.63 $ 0.43 $ 0.53 Diluted $ 0.50 $ 0.63 $ 0.43 $ 0.53 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 (1) Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the 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 losses recognized by the Company upon the partial redemptions of its 2022 Notes in the 2019 third quarter and 2018 third quarter. (5) In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties and a $16.9 million ( $0.05 per basic and diluted share) decrease in income tax expense and corresponding increase in net income was recognized as discussed in Note 9. Income Taxes .

Organization and Summary of S_2

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Description of the Company	Description of the Company Continental Resources, Inc. (the “Company”) was 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 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 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
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 are presented separately from transportation expenses, 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 $192.0 million and $162.3 million for the years ended December 31, 2019 and 2018 , respectively. 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. The Company currently takes certain processed residue gas volumes in kind in lieu of monetary settlement, but does not currently take NGL volumes. 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 $33.7 million and $29.3 million for the years ended December 31, 2019 and 2018 , respectively. 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, 2019 , the Company had cash deposits in excess of federally insured amounts of approximately $38.1 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's allowance for doubtful accounts, as accounted for under legacy U.S. GAAP in effect as of December 31, 2019, was determined 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 $2.4 million as of December 31, 2019 and 2018 , respectively, which is included in “Receivables —
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, 2019 , sales to the Company’s largest purchaser accounted for approximately 13% 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 2019 . 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, 2019 and 2018 consisted of the following: December 31, In thousands 2019 2018 Tubular goods and equipment $ 14,880 $ 14,623 Crude oil 94,656 73,921 Total $ 109,536 $ 88,544
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 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.
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. Sales of proved properties constituting a part of an amortization base are accounted for as normal retirements with no gain or loss recognized if doing so does not significantly affect the unit-of-production amortization rate. Unit-of-production rates are revised whenever there is an indication of a need, but at least in conjunction with semi-annual reserve reports. Revisions are accounted for prospectively as changes in accounting estimates.
Asset Retirement Obligations	Asset retirement obligations The Company accounts for its asset retirement obligations by recording the fair value of a liability for an asset retirement obligation in the period in which a legal obligation is incurred and a corresponding increase in the carrying amount of the related long-lived asset. Subsequently, the capitalized asset retirement costs are charged to expense through the depreciation, depletion and amortization of crude oil and natural gas properties and the liability is accreted to the expected future abandonment cost ratably over the related asset’s life.
Asset Impairment	Asset impairment Proved crude oil and natural gas properties are reviewed for impairment on a field-by-field basis each quarter. The estimated future cash flows expected in connection with the field are compared to the carrying amount of the field to determine if the carrying amount is recoverable. If the carrying amount of the field exceeds its estimated undiscounted future cash flows, the carrying amount of the field is reduced to its estimated fair value.
Debt Issuance Costs	Debt issuance costs
Derivative Instruments	Derivative instruments The Company recognizes its derivative instruments, if any, 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. Historically, the Company has not designated its derivative instruments as hedges for accounting purposes and, as a result, marked its derivative instruments to fair value and recognized the changes in fair value in the consolidated statements of comprehensive income under the caption “ Gain (loss) on natural gas derivatives, net .”
Fair Value of Financial Instruments	Fair value of financial instruments The Company’s financial instruments consist primarily of cash, trade receivables, trade payables, derivative instruments and long-term debt. See Note 6. Fair Value Measurements for a discussion of the methods used to determine fair value for the Company’s financial instruments and the quantification of fair value for its derivatives and long-term debt obligations at December 31, 2019 and 2018 .
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 period-end. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. The Company’s policy is to recognize penalties and interest related to unrecognized tax benefits, if any, in income tax expense. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Earnings Per Share	Earnings per share attributable to Continental Resources
Foreign Currency Transactions and Translations Policy	Foreign currency translation In 2014, the Company initiated operations in Canada through a wholly-owned Canadian subsidiary. The Company’s operations in Canada are immaterial and were sold in the fourth quarter of 2019. See Note 16. Property Dispositions for further discussion. The Company 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 were 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.
New Accounting Pronouncements	Adoption of new accounting pronouncement in 2019 On January 1, 2019 the Company adopted Accounting Standards Update ("ASU") 2016-02, Leases (Topic 842) . See Note 10. Leases for discussion of the adoption impact and the applicable disclosures required by the new guidance. New accounting pronouncements not yet adopted at December 31, 2019 Credit losses – In June 2016, the Financial Accounting Standards Board ("FASB") issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments . This standard changes how entities measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard replaced the previously required incurred loss approach with a forward-looking expected credit loss model for accounts receivable and other financial instruments measured at amortized cost. The standard became effective for interim and annual periods beginning after December 15, 2019. The Company adopted the new standard on January 1, 2020 using a modified retrospective approach through a cumulative-effect adjustment to retained earnings as of the effective date, which had an immaterial impact. Historically, the Company's credit losses on crude oil and natural gas sales receivables and joint interest receivables have been immaterial. Income taxes – In December 2019, the FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes. This standard eliminates certain exceptions to the guidance in Topic 740 related to the approach for intraperiod tax allocation, the methodology for calculating income taxes in an interim period, and the recognition of deferred tax liabilities for outside basis differences. The new guidance also clarifies certain aspects of the existing guidance, among other things. The standard is effective for interim and annual periods beginning after December 15, 2020 and shall be applied on either a prospective basis, a retrospective basis for all periods presented, or a modified retrospective basis through a cumulative-effect adjustment to retained earnings depending on which aspects of the new standard are applicable to an entity. The Company is in the process of evaluating the new standard and is unable to estimate its financial impact, if any, at this time.

Organization and Summary of S_3

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Components of Inventories	The components of inventory as of December 31, 2019 and 2018 consisted of the following: December 31, In thousands 2019 2018 Tubular goods and equipment $ 14,880 $ 14,623 Crude oil 94,656 73,921 Total $ 109,536 $ 88,544
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, 2017 through December 31, 2019 : In thousands 2019 2018 2017 Asset retirement obligations at January 1 $ 141,360 $ 114,406 $ 96,178 Accretion expense 8,443 6,985 5,886 Revisions (1) (1,762 ) 13,075 7,801 Plus: Additions for new assets 8,392 9,070 6,884 Less: Plugging costs and sold assets (2,760 ) (2,176 ) (2,343 ) Total asset retirement obligations at December 31 $ 153,673 $ 141,360 $ 114,406 Less: Current portion of asset retirement obligations at December 31 (2) 1,899 4,374 2,612 Non-current portion of asset retirement obligations at December 31 $ 151,774 $ 136,986 $ 111,794 (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 per share attributable to the Company for the years ended December 31, 2019 , 2018 and 2017 . Year ended December 31, In thousands, except per share data 2019 2018 2017 Net income attributable to Continental Resources (numerator) (1) $ 775,641 $ 988,317 $ 789,447 Weighted average shares (denominator): Weighted average shares - basic 370,699 371,854 371,066 Non-vested restricted stock 1,839 2,984 2,702 Weighted average shares - diluted 372,538 374,838 373,768 Net income per share attributable to Continental Resources: (1) Basic $ 2.09 $ 2.66 $ 2.13 Diluted $ 2.08 $ 2.64 $ 2.11 (1) The Company sold its Canadian subsidiary and associated properties in 2019 which resulted in a decrease in income tax expense and corresponding increase in net income via the recognition of an income tax benefit of $16.9 million ( $0.05 per basic and diluted share). See Note 9. Income Taxes for further discussion. Additionally, results for 2017 include 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 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. Results for 2017 also include a $59.6 million pre-tax loss accrual recognized in conjunction with a litigation settlement as discussed in Note 11. Commitments and Contingencies , which resulted in an after-tax decrease in 2017 net income of $37.0 million ( $0.10 per basic and diluted share).

Supplemental Cash Flow Inform_2

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 Supplemental cash flow information: Cash paid for interest $ 267,421 $ 270,927 $ 281,058 Cash paid for income taxes 229 — 2 Cash received for income tax refunds 107 7,893 257 Non-cash investing activities: Asset retirement obligation additions and revisions, net 6,630 22,145 14,685

Net Property and Equipment (Tab

Net Property and Equipment (Tables)	12 Months Ended
	Dec. 31, 2019
Property, Plant and Equipment, Net [Abstract]
Schedule of Net Property and Equipment	Net property and equipment includes the following at December 31, 2019 and 2018 . December 31, In thousands 2019 2018 Proved crude oil and natural gas properties $ 26,611,429 $ 24,060,625 Unproved crude oil and natural gas properties 319,592 291,564 Service properties, equipment and other 336,439 324,758 Total property and equipment 27,267,460 24,676,947 Accumulated depreciation, depletion and amortization (12,769,734 ) (10,807,147 ) Net property and equipment $ 14,497,726 $ 13,869,800

Accrued Liabilities and Other (

Accrued Liabilities and Other (Tables)	12 Months Ended
	Dec. 31, 2019
Accrued Liabilities and Other Liabilities [Abstract]
Schedule of Accrued Liabilities and Other	Accrued liabilities and other includes the following at December 31, 2019 and 2018 : December 31, In thousands 2019 2018 Prepaid advances from joint interest owners $ 50,021 $ 53,674 Accrued compensation 61,483 69,338 Accrued production taxes, ad valorem taxes and other non-income taxes 59,057 52,105 Accrued interest 56,953 64,483 Accrued litigation settlement (see Note 11) — 19,753 Current portion of asset retirement obligations 1,899 4,374 Other 955 3,092 Accrued liabilities and other $ 230,368 $ 266,819

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Derivative [Line Items]
Realized and Unrealized Gains and Losses on Derivative Instruments	Year ended December 31, In thousands 2019 2018 2017 Cash received (paid) on derivatives: Natural gas fixed price swaps $ 58,836 $ (36,939 ) $ 40,095 Natural gas collars 5,859 — (10,539 ) Cash received (paid) on derivatives, net 64,695 (36,939 ) 29,556 Non-cash gain (loss) on derivatives: Natural gas fixed price swaps (10,130 ) 7,527 18,960 Natural gas collars (5,482 ) 5,482 43,131 Non-cash gain (loss) on derivatives, net (15,612 ) 13,009 62,091 Gain (loss) on natural gas derivatives, net $ 49,083 $ (23,930 ) $ 91,647
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 2019 2018 Commodity derivative assets: Gross amounts of recognized assets $ — $ 16,789 Gross amounts offset on balance sheet — (1,177 ) Net amounts of assets on balance sheet — 15,612 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 2019 2018 Derivative assets $ — $ 15,612 Noncurrent derivative assets — — Net amounts of assets on balance sheet — 15,612 Derivative liabilities — — Noncurrent derivative liabilities — — Net amounts of liabilities on balance sheet — — Total derivative assets, net $ — $ 15,612

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value Disclosures [Abstract]
Valuation of Financial Instruments by Pricing Levels	The following table summarizes the valuation of derivative instruments by pricing levels that were accounted for at fair value on a recurring basis as of December 31, 2018 . The Company had no outstanding commodity derivative instruments at December 31, 2019 . 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
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 2024 (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. Year ended December 31, In thousands 2019 2018 2017 Proved property impairments $ 3,745 $ 18,037 $ 82,340 Unproved property impairments 82,457 107,173 155,030 Total $ 86,202 $ 125,210 $ 237,370
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, 2019 December 31, 2018 In thousands Carrying Amount Estimated Fair Value Carrying Amount Estimated Fair Value Debt: Revolving credit facility $ 55,000 $ 55,000 $ — $ — Note payable 5,351 5,400 7,700 7,700 5% Senior Notes due 2022 1,099,165 1,108,700 1,598,404 1,590,900 4.5% Senior Notes due 2023 1,491,339 1,571,400 1,488,960 1,476,300 3.8% Senior Notes due 2024 994,310 1,034,200 993,151 947,200 4.375% Senior Notes due 2028 989,661 1,063,700 988,617 942,800 4.9% Senior Notes due 2044 691,688 742,000 691,517 618,800 Total debt $ 5,326,514 $ 5,580,400 $ 5,768,349 $ 5,583,700

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2019
Debt Disclosure [Abstract]
Long-Term Debt	Long-term debt, net of unamortized discounts, premiums, and debt issuance costs totaling $33.9 million and $39.4 million at December 31, 2019 and 2018 , respectively, consists of the following. December 31, In thousands 2019 2018 Revolving credit facility $ 55,000 $ — Note payable 5,351 7,700 5% Senior Notes due 2022 1,099,165 1,598,404 4.5% Senior Notes due 2023 1,491,339 1,488,960 3.8% Senior Notes due 2024 994,310 993,151 4.375% Senior Notes due 2028 989,661 988,617 4.9% Senior Notes due 2044 691,688 691,517 Total debt 5,326,514 5,768,349 Less: Current portion of long-term debt 2,435 2,360 Long-term debt, net of current portion $ 5,324,079 $ 5,765,989
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, 2019 . 2022 Notes (1) 2023 Notes 2024 Notes 2028 Notes 2044 Notes Face value (in thousands) $1,100,000 $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, 2019
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 periods presented. Year ended December 31, 2019 2018 In thousands North Region South Region Total North Region South Region Total Crude oil revenues: Operated properties $ 2,365,574 $ 786,652 $ 3,152,226 $ 2,330,711 $ 603,070 $ 2,933,781 Non-operated properties 727,068 50,700 777,768 790,435 68,378 858,813 Total crude oil revenues 3,092,642 837,352 3,929,994 3,121,146 671,448 3,792,594 Natural gas revenues: Operated properties 109,668 411,464 521,132 214,741 547,247 761,988 Non-operated properties 25,188 38,075 63,263 60,738 63,402 124,140 Total natural gas revenues 134,856 449,539 584,395 275,479 610,649 886,128 Crude oil and natural gas sales $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 3,396,625 $ 1,282,097 $ 4,678,722 Timing of revenue recognition Goods transferred at a point in time $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 3,396,625 $ 1,282,097 $ 4,678,722 Goods transferred over time — — — — — — $ 3,227,498 $ 1,286,891 $ 4,514,389 $ 3,396,625 $ 1,282,097 $ 4,678,722

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
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 2019 2018 2017 Current income tax provision (benefit): United States federal (1) $ — $ (7,781 ) $ (7,781 ) Various states — 5 — Total current income tax (benefit) — (7,776 ) (7,781 ) Deferred income tax provision (benefit): United States federal - taxation on operations 191,328 282,947 81,054 United States federal - effect of US tax reform — — (713,655 ) Various states 21,361 31,931 7,002 Total deferred income tax provision (benefit) 212,689 314,878 (625,599 ) Provision (benefit) for income taxes $ 212,689 $ 307,102 $ (633,380 ) Effective tax rate 21.5 % 23.7 % (405.8 %)
Schedule of Provision for Income Taxes with Income Tax at Federal Statutory Rate	Year ended December 31, In thousands, except rates 2019 2018 2017 Income before income taxes $ 987,162 $ 1,296,802 $ 156,067 U.S. federal statutory tax rate 21.0 % 21.0 % 35.0 % Expected income tax provision based on US statutory tax rate 207,304 272,328 54,623 Items impacting the effective tax rate: State income taxes, net of federal benefit 31,967 45,920 4,682 Effect of US tax reform legislation — — (713,655 ) Tax benefit (deficiency) from stock-based compensation (7,971 ) (259 ) 3,932 Non-deductible compensation 8,282 2,932 13,813 Sale of Canadian subsidiary and assets (16,860 ) — — Other, net (10,033 ) (13,819 ) 3,225 Provision (benefit) for income taxes $ 212,689 $ 307,102 $ (633,380 ) Effective tax rate 21.5 % 23.7 % (405.8 %)
Components of Deferred Tax Assets and Liabilities	The components of the Company’s deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are reflected in the table below. December 31, In thousands 2019 2018 Deferred tax assets United States net operating loss carryforwards $ 550,086 $ 549,166 Canadian net operating loss carryforwards — 19,633 Equity compensation 13,157 13,122 Other 18,466 13,622 Total deferred tax assets 581,709 595,543 Canadian valuation allowance — (19,633 ) Total deferred tax assets, net of valuation allowance 581,709 575,910 Deferred tax liabilities Property and equipment (2,367,137 ) (2,144,767 ) Other (1,697 ) (5,579 ) Total deferred tax liabilities (2,368,834 ) (2,150,346 ) Deferred income tax liabilities, net $ (1,787,125 ) $ (1,574,436 )

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Schedule of Future Minimum Rental Payments for Operating Leases [Table Text Block]	At December 31, 2018, the minimum future rental commitments under legacy 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 were not required to be recognized on the Company's balance sheet under legacy U.S. GAAP in effect as of December 31, 2018. In thousands Total amount as of December 31, 2018 2019 $ 1,535 2020 1,042 2021 833 2022 805 2023 745 Thereafter 6,795 Total obligations as of December 31, 2018 $ 11,755
Lessee, Operating Lease, Liability, Maturity [Table Text Block]	Minimum future commitments by year for the Company's operating leases as of December 31, 2019 are presented in the table below. Such commitments are reflected at undiscounted values and are reconciled to the discounted present value recognized on the balance sheet. In thousands Amount 2020 $ 3,999 2021 750 2022 734 2023 667 2024 411 Thereafter 5,755 Total operating lease liabilities, at undiscounted value $ 12,316 Less: Imputed interest (3,188 ) Total operating lease liabilities, at discounted present value $ 9,128 Less: Current portion of operating lease liabilities (3,695 ) Operating lease liabilities, net of current portion $ 5,433
Lessee, Operating Lease, Disclosure [Table Text Block]	The Company’s lease liabilities recognized on the balance sheet as a lessee totaled $9.1 million as of December 31, 2019 at discounted present value, which is comprised of the asset classes reflected in the table below. All leases recognized on the Company's balance sheet are classified as operating leases. In thousands Amount Drilling rig commitments $ 3,154 Surface use agreements 4,487 Field equipment 1,164 Other 323 Total $ 9,128
Lease, Cost [Table Text Block]	Additional information for the Company's operating leases is presented below. Lease costs are reflected at gross amounts and primarily represent costs incurred for drilling rigs, most of which are short term contracts that are not recognized as right-of-use assets and lease liabilities on the balance sheet. Variable lease costs primarily represent differences between minimum payment obligations and actual operating day-rate charges incurred by the Company for its long term drilling rig contracts. In thousands, except weighted average data Year ended December 31, 2019 Lease costs: Operating lease costs $ 11,130 Variable lease costs 11,930 Short-term lease costs 176,586 Total lease costs $ 199,646 Other information: Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,208 Operating cash flows from operating leases included in lease liabilities 804 Weighted average remaining lease term as of December 31, 2019 (in years) 11.5 Weighted average discount rate as of December 31, 2019 4.9 %

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2019
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, was $52.0 million , $47.2 million , and $45.9 million for the years ended December 31, 2019 , 2018 and 2017 , 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, 2016 to December 31, 2019 is presented below. Number of Weighted 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 Granted 1,526,825 43.21 Vested (1,737,304 ) 24.19 Forfeited (350,022 ) 47.13 Non-vested restricted shares at December 31, 2019 3,461,908 $ 46.82

Shareholders' Equity Attribut_2

Shareholders' Equity Attributable to Continental Resources (Tables)	12 Months Ended
	Dec. 31, 2019
Shareholders' Equity Attributable to Continental Resources [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, 2019 , 2018 , and 2017 : Year ended December 31, In thousands 2019 2018 2017 Beginning accumulated other comprehensive income (loss), net of tax $ 415 $ 307 $ (260 ) Foreign currency translation adjustments 140 108 567 Release of cumulative translation adjustments (1) (555 ) — — Income taxes (2) — — — Other comprehensive income (loss), net of tax (415 ) 108 567 Ending accumulated other comprehensive income, net of tax $ — $ 415 $ 307 (1) In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 16. Property Dispositions for further information. (2) A valuation allowance had 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, 2019
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, 2019 , 2018 and 2017 . Year ended December 31, In thousands 2019 2018 2017 Crude oil and natural gas sales (1) $ 4,514,389 $ 4,678,722 $ 2,982,966 Production expenses (444,649 ) (390,423 ) (324,214 ) Production taxes (357,988 ) (353,140 ) (208,278 ) Transportation expenses (1) (225,649 ) (191,587 ) — Exploration expenses (14,667 ) (7,642 ) (12,393 ) Depreciation, depletion, amortization and accretion (1,997,854 ) (1,839,241 ) (1,652,180 ) Property impairments (86,202 ) (125,210 ) (237,370 ) Income tax (provision) benefit (2) (323,025 ) (434,047 ) 504,475 Results from crude oil and natural gas producing activities $ 1,064,355 $ 1,337,432 $ 1,053,006
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, 2019 , 2018 and 2017 are presented below: Year ended December 31, In thousands 2019 2018 2017 Property acquisition costs: Proved $ 51,558 $ 31,579 $ 8,446 Unproved 312,680 329,586 220,875 Total property acquisition costs 364,238 361,165 229,321 Exploration Costs 50,143 81,015 123,461 Development Costs 2,388,582 2,478,327 1,695,954 Total $ 2,802,963 $ 2,920,507 $ 2,048,736
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, 2019 and 2018 are as follows: December 31, In thousands 2019 2018 Proved crude oil and natural gas properties $ 26,611,429 $ 24,060,625 Unproved crude oil and natural gas properties 319,592 291,564 Total 26,931,021 24,352,189 Less accumulated depreciation, depletion and amortization (12,635,247 ) (10,680,870 ) Net capitalized costs $ 14,295,774 $ 13,671,319
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 2019 2018 2017 Balance at January 1 $ 3,959 $ 31,356 $ 34,852 Additions to capitalized exploratory well costs pending determination of proved reserves 28,280 45,088 79,451 Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves (23,200 ) (72,347 ) (81,035 ) Capitalized exploratory well costs charged to expense (2,782 ) (138 ) (1,912 ) Balance at December 31 $ 6,257 $ 3,959 $ 31,356 Number of gross wells 11 16 37

Supplemental Crude Oil and Na_2

Supplemental Crude Oil and Natural Gas Information (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
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, 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 (88,307 ) (363,239 ) (148,848 ) Extensions, discoveries and other additions 162,710 1,213,947 365,034 Production (72,267 ) (311,865 ) (124,244 ) Sales of minerals in place (803 ) (6,224 ) (1,840 ) Purchases of minerals in place 1,758 30,238 6,798 Proved reserves as of December 31, 2019 760,187 5,154,471 1,619,265
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, 2019 , 2018 and 2017 : December 31, 2019 2018 2017 Proved Developed Reserves Crude oil (MBbl) 336,405 347,825 318,707 Natural Gas (MMcf) 2,226,117 1,964,289 1,699,161 Total (MBoe) 707,424 675,206 601,901 Proved Undeveloped Reserves Crude oil (MBbl) 423,782 409,271 322,242 Natural Gas (MMcf) 2,928,354 2,627,325 2,441,120 Total (MBoe) 911,841 847,159 729,094 Total Proved Reserves Crude oil (MBbl) 760,187 757,096 640,949 Natural Gas (MMcf) 5,154,471 4,591,614 4,140,281 Total (MBoe) 1,619,265 1,522,365 1,330,995
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, 2019 , 2018 and 2017 . Discounted future net cash flows attributable to noncontrolling interests are not material relative to the Company's consolidated amounts and are not separately presented below. December 31, In thousands 2019 2018 2017 Future cash inflows $ 49,893,470 $ 61,510,432 $ 42,574,897 Future production costs (15,309,672 ) (16,139,001 ) (11,159,362 ) Future development and abandonment costs (10,033,887 ) (9,706,114 ) (6,487,097 ) Future income taxes (1) (3,351,657 ) (6,012,439 ) (3,488,755 ) Future net cash flows 21,198,254 29,652,878 21,439,683 10% annual discount for estimated timing of cash flows (10,736,613 ) (13,968,061 ) (10,969,506 ) Standardized measure of discounted future net cash flows $ 10,461,641 $ 15,684,817 $ 10,470,177
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 2019 2018 2017 Standardized measure of discounted future net cash flows at January 1 $ 15,684,817 $ 10,470,177 $ 5,510,223 Extensions, discoveries and improved recoveries, less related costs 1,649,322 5,162,635 1,462,629 Revisions of previous quantity estimates (1,564,503 ) (3,522,428 ) (1,004,355 ) Changes in estimated future development and abandonment costs 1,401,513 1,063,089 743,657 Purchases (sales) of minerals in place, net 49,330 (9,192 ) (41,077 ) Net change in prices and production costs (6,591,347 ) 4,224,473 3,808,116 Accretion of discount 1,865,034 1,183,347 665,507 Sales of crude oil and natural gas produced, net of production costs (3,486,103 ) (3,743,572 ) (2,450,474 ) Development costs incurred during the period 1,557,121 1,134,153 1,045,875 Change in timing of estimated future production and other (1,690,779 ) 1,324,365 948,519 Change in income taxes 1,587,236 (1,602,230 ) (218,443 ) Net change (5,223,176 ) 5,214,640 4,959,954 Standardized measure of discounted future net cash flows at December 31 $ 10,461,641 $ 15,684,817 $ 10,470,177

Quarterly Financial Data (Una_2

Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2019
Quarterly Financial Information Disclosure [Abstract]
Schedule Of Quarterly Financial Data	The Company’s unaudited quarterly financial data for 2019 and 2018 is summarized below. Quarter ended In thousands, except per share data March 31 June 30 September 30 December 31 2019 Total revenues (1) $ 1,124,234 $ 1,208,382 $ 1,104,197 $ 1,195,134 Gain (loss) on natural gas derivatives, net (1) $ (1,124 ) $ 53,448 $ 1,195 $ (4,436 ) Property impairments (2) $ 25,316 $ 21,339 $ 20,199 $ 19,348 Gain (loss) on sale of assets, net (3) $ 252 $ (364 ) $ (535 ) $ 1,182 Income from operations $ 304,965 $ 379,847 $ 278,724 $ 293,876 Loss on extinguishment of debt (4) $ — $ — $ (4,584 ) $ — Net income (5) $ 186,493 $ 236,450 $ 157,422 $ 194,108 Net income attributable to Continental Resources (5) $ 186,976 $ 236,557 $ 158,162 $ 193,946 Net income per share attributable to Continental Resources: (5) Basic $ 0.50 $ 0.63 $ 0.43 $ 0.53 Diluted $ 0.50 $ 0.63 $ 0.43 $ 0.53 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 (1) Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods. (2) Property impairments have been shown separately to illustrate the 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 losses recognized by the Company upon the partial redemptions of its 2022 Notes in the 2019 third quarter and 2018 third quarter. (5) In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties and a $16.9 million ( $0.05 per basic and diluted share) decrease in income tax expense and corresponding increase in net income was recognized as discussed in Note 9. Income Taxes .

Organization and Summary of S_4

Organization and Summary of Significant Accounting Policies - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Organization And Summary Of Significant Accounting Policies [Line Items]
Sale of Canadian subsidiary and assets	$ 16,860	$ 0	$ 0
Tax benefit from US tax reform legislation	0	0	(713,655)
Accrued litigation settlement	0	19,753
Allowance for doubtful accounts receivable	2,400	2,400
Unamortized Debt Issuance Expense	35,300	45,100
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	19,600
Cash deposits in excess of federally insured amounts	38,100
Net asset retirement costs	55,800	57,700
Capitalized debt issue costs, relating to long-term debt	40,000	51,200
Accumulated amortization, relating to capitalized debt issue costs	73,700	62,500
Amortization expense related to capitalized debt issuance costs	8,300	9,300	9,100
Deferred Tax Assets, Valuation Allowance	0	19,633
Transportation expenses	225,649	191,587	0
Estimated litigation liability, after tax			$ 37,000
Diluted eps estimated litigation settlement			$ 0.10
Revolving Credit Facility [Member]
Organization And Summary Of Significant Accounting Policies [Line Items]
Unamortized Debt Issuance Expense	$ 4,700	$ 6,100
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	13.00%

Organization and Summary of S_5

Organization and Summary of Significant Accounting Policies - Components of Inventories (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Tubular goods and equipment	$ 14,880	$ 14,623
Crude oil	94,656	73,921
Total	$ 109,536	$ 88,544

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, 2019
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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at January 1		$ 141,360	$ 114,406	$ 96,178
Accretion expense		8,443	6,985	5,886
Revisions	[1]	(1,762)	13,075	7,801
Plus: Additions for new assets		8,392	9,070	6,884
Less: Plugging costs and sold assets		(2,760)	(2,176)	(2,343)
Total asset retirement obligations at December 31		$ 141,360	$ 114,406	$ 96,178	$ 153,673	$ 141,360	$ 114,406
Less: Current portion of asset retirement obligations at December 31	[2]				1,899	4,374	2,612
Non-current portion of asset retirement obligations at December 31					$ 151,774	$ 136,986	$ 111,794
[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, shares in Thousands	3 Months Ended									12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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
Sale of Canadian subsidiary and assets										$ (16,860,000)	$ 0	$ 0
Diluted EPS impact from sale of Canadian assets	$ 0.05
Income (numerator):
Net income - basic and diluted	$ 193,946,000	[1]	$ 158,162,000	$ 236,557,000	$ 186,976,000	$ 197,738,000	$ 314,169,000	$ 242,464,000	$ 233,946,000	$ 775,641,000	$ 988,317,000	$ 789,447,000
Weighted average shares - basic										370,699	371,854	371,066
Non-vested restricted stock										1,839	2,984	2,702
Weighted average shares - diluted										372,538	374,838	373,768
Net income per share:
Basic (in dollars per share)	$ 0.53	[1]	$ 0.43	$ 0.63	$ 0.50	$ 0.53	$ 0.84	$ 0.65	$ 0.63	$ 2.09	$ 2.66	$ 2.13
Diluted (in dollars per share)	$ 0.53	[1]	$ 0.43	$ 0.63	$ 0.50	$ 0.53	$ 0.84	$ 0.65	$ 0.63	$ 2.08	$ 2.64	$ 2.11
[1]	In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties and a $16.9 million ( $0.05 per basic and diluted share) decrease in income tax expense and corresponding increase in net income was recognized as discussed in Note 9. Income Taxes

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, 2019USD ($)
New Accounting Pronouncements [Abstract]
ASU 2016-02 Lease assets and liabilities recognition	$ 19

Supplemental Cash Flow Inform_3

Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 267,421	$ 270,927	$ 281,058
Cash paid for income taxes	229	0	2
Cash received for income tax refunds	107	7,893	257
Non-cash investing activities:
ASU 2016-02 Lease assets and liabilities recognition	19,000
Accrued distributions to noncontrolling interests	1,500	1,300
Accrued contributions from noncontrolling interests	5,600	9,300
Asset Retirement Obligation, Additions or Revisions	6,630	22,145	$ 14,685
Capital Expenditures Incurred but Not yet Paid	$ 262,700	$ 317,500

Net Property and Equipment - Sc

Net Property and Equipment - Schedule of Net Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment, Net [Abstract]
Proved crude oil and natural gas properties	$ 26,611,429	$ 24,060,625
Unproved crude oil and natural gas properties	319,592	291,564
Service properties, equipment and other	336,439	324,758
Total property and equipment	27,267,460	24,676,947
Accumulated depreciation, depletion and amortization	(12,769,734)	(10,807,147)
Net property and equipment	$ 14,497,726	$ 13,869,800

Accrued Liabilities and Other -

Accrued Liabilities and Other - Schedule of Accrued Liabilities and Other (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accrued Liabilities and Other Liabilities [Abstract]
Prepaid advances from joint interest owners		$ 50,021	$ 53,674
Accrued compensation		61,483	69,338
Accrued production taxes, ad valorem taxes and other non-income taxes		59,057	52,105
Accrued interest		56,953	64,483
Accrued litigation settlement		0	19,753
Current portion of asset retirement obligations	[1]	1,899	4,374	$ 2,612
Other		955	3,092
Accrued liabilities and other		$ 230,368	$ 266,819
[1]	Balance is included in the caption “Accrued liabilities and other” in the consolidated balance sheets.

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, 2019	[1]	Sep. 30, 2019	[1]	Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Dec. 31, 2018	[1]	Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	$ (15,612)	$ 13,009	$ 58,031
Gain (loss) on natural gas derivatives, net	$ (4,436)		$ 1,195		$ 53,448		$ (1,124)		$ (19,394)		$ (2,025)		$ (12,685)		$ 10,174		49,083	(23,930)	91,647
Fixed Price Swaps [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	58,836	(36,939)	40,095
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(10,130)	7,527	18,960
Collars [Member] | Natural Gas [Member]
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	5,859	0	(10,539)
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(5,482)	5,482	43,131
Crude Oil and Natural Gas
Cash received (paid) on derivatives:
Cash received (paid) on derivatives, net																	64,695	(36,939)	29,556
Non-cash gain (loss) on derivatives:
Non-cash gain (loss) on derivatives, net																	(15,612)	13,009	62,091
Gain (loss) on natural gas derivatives, net																	$ 49,083	$ (23,930)	$ 91,647
[1]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.

Derivative Instruments Derivati

Derivative Instruments Derivative Instruments - Gross Amounts of Recognized Derivative Assets and Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative [Line Items]
Commodity derivative assets, Gross amounts of recognized assets	$ 0	$ 16,789
Commodity derivative assets, Gross amounts offset on balance sheet	0	(1,177)
Derivative assets, Net amounts of assets on balance sheet	0	15,612
Commodity derivative liability, Gross amounts of recognized liabilities	0	(1,177)
Commodity derivative liability, Gross amounts offset on balance sheet	0	1,177
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, 2019	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative assets	$ 0	$ 15,612
Noncurrent derivative assets	0	0
Derivative assets, Net amounts of assets on balance sheet	0	15,612
Derivative liabilities	0	0
Noncurrent derivative liabilities	0	0
Derivative liability, Net amounts of liabilities on balance sheet	0	0
Total derivative assets, net	$ 0	$ 15,612

Fair Value Measurements - Valua

Fair Value Measurements - Valuation of Financial Instruments by Pricing Levels (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivative assets (liabilities):
Derivative assets (liabilities)	$ 0	$ 15,612
Swap [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		10,130
Collars [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		5,482
Fair Value, Inputs, Level 1 [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		0
Fair Value, Inputs, Level 1 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		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
Fair Value, Inputs, Level 2 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		10,130
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
Fair Value, Inputs, Level 3 [Member] | Fixed Price Swaps [Member]
Derivative assets (liabilities):
Derivative assets (liabilities)		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, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 3,745	$ 18,037	$ 82,340
Estimated fair value of proved properties			72,000
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, 2019

[1]

Sep. 30, 2019

[1]

Jun. 30, 2019

[1]

Mar. 31, 2019

[1]

Dec. 31, 2018

[1]

Sep. 30, 2018

[1]

Jun. 30, 2018

[1]

Mar. 31, 2018

[1]

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

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

Proved property impairments

$ 3,745

$ 18,037

$ 82,340

Unproved property impairments

82,457

107,173

155,030

Total

$ 19,348

$ 20,199

$ 21,339

$ 25,316

$ 38,494

$ 23,770

$ 29,162

$ 33,784

$ 86,202

$ 125,210

237,370

Estimated fair value of proved properties

72,000

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, 2019	Dec. 31, 2018
5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2022
Debt instrument, stated interest rate	5.00%
4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2023
Debt instrument, stated interest rate	4.50%
3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2024
Debt instrument, stated interest rate	3.80%
Senior notes		$ 993,151
4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2028
Debt instrument, stated interest rate	4.375%
Senior notes		988,617
4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Debt instrument, maturity date	2044
Debt instrument, stated interest rate	4.90%
Senior notes		691,517
Carrying Amount [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	$ 55,000	0
Note payable	5,351	7,700
Total debt	5,326,514	5,768,349
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,099,165	1,598,404
Carrying Amount [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,491,339	1,488,960
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	994,310	993,151
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	989,661	988,617
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	691,688	691,517
Fair Value [Member]
Fair Value Measurements [Line Items]
Revolving credit facility	55,000	0
Note payable	5,400	7,700
Total debt	5,580,400	5,583,700
Fair Value [Member] | 5% Senior Notes due 2022 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,108,700	1,590,900
Fair Value [Member] | 4 1/2% Senior Notes due 2023 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,571,400	1,476,300
Fair Value [Member] | 3.8% Senior Notes due 2024 [Member]
Fair Value Measurements [Line Items]
Senior notes	1,034,200	947,200
Fair Value [Member] | 4.375% Senior Notes Due 2028
Fair Value Measurements [Line Items]
Senior notes	1,063,700	942,800
Fair Value [Member] | 4.9% Senior Notes due 2044 [Member]
Fair Value Measurements [Line Items]
Senior notes	$ 742,000	$ 618,800

Long-Term Debt - Long-Term Debt

Long-Term Debt - Long-Term Debt (Detail) - USD ($) $ in Thousands	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019	[1]	Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Dec. 31, 2018		Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 12, 2019	Aug. 16, 2018
Debt Instrument [Line Items]
Debt Instrument, Unamortized Discount (Premium) and Debt Issuance Costs, Net	$ 33,900								$ 39,400								$ 33,900	$ 39,400
TotalRedemptionAmount																				$ 516,500	$ 415,100
Less: Current portion of long-term debt	(2,435)								(2,360)								(2,435)	(2,360)
Long-term debt, net of current portion	5,324,079								5,765,989								5,324,079	5,765,989
Loss on extinguishment of debt	$ 0	[1]	$ (4,584)		$ 0		$ 0		0	[1]	$ (7,133)		$ 0		$ 0		$ (4,584)	(7,133)	$ (554)
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									993,151									993,151
Debt instrument, stated interest rate	3.80%																3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes									988,617									988,617
Debt instrument, stated interest rate	4.375%																4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes									691,517									691,517
Debt instrument, stated interest rate	4.90%																4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Revolving credit facility	$ 55,000								0								$ 55,000	0
Note payable	5,351								7,700								5,351	7,700
Total debt	5,326,514								5,768,349								5,326,514	5,768,349
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,099,165								1,598,404								1,099,165	1,598,404
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,491,339								1,488,960								1,491,339	1,488,960
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	994,310								993,151								994,310	993,151
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	989,661								988,617								989,661	988,617
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,688								$ 691,517								$ 691,688	$ 691,517
[1]	See Note 7. Long-Term Debt for discussion of the losses recognized by the Company upon the partial redemptions of its 2022 Notes in the 2019 third quarter and 2018 third quarter.

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended																	6 Months Ended	12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019	[1]	Mar. 31, 2019	[1]	Dec. 31, 2018		Sep. 30, 2018	[1]	Jun. 30, 2018	[1]	Mar. 31, 2018	[1]	Sep. 30, 2017	Jun. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 12, 2019	Aug. 16, 2018
Debt Instrument [Line Items]
Proceeds from sale of assets																			$ 88,734	$ 54,458	$ 144,353
Loss on extinguishment of debt	$ 0	[1]	$ 4,584	[1]	$ 0		$ 0		$ 0	[1]	$ 7,133		$ 0		$ 0				4,584	7,133	554
TotalRedemptionAmount																						$ 516,500	$ 415,100
Aggregate amount of lender commitments on credit facility	1,500,000																		$ 1,500,000
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	0	990,000
Repayments of Lines of Credit																			1,161,000	2,212,000	$ 2,019,000
Current portion of long-term debt	2,435								2,360										2,435	2,360
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Repurchased Face Amount																						$ 500,000	$ 400,000
Debt Instrument, Redemption Price, Percentage			100.833%														101.667%
Debt Instrument, Face Amount	1,100,000																		$ 1,100,000
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
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Weighted Average Interest Rate	3.30%																		3.30%
Line of Credit Facility, Remaining Borrowing Capacity	$ 1,450,000																		$ 1,450,000
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									993,151											993,151
Debt instrument, stated interest rate	3.80%																		3.80%
4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes									988,617											988,617
Debt instrument, stated interest rate	4.375%																		4.375%
4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes									691,517											691,517
Debt instrument, stated interest rate	4.90%																		4.90%
Carrying Amount [Member]
Debt Instrument [Line Items]
Line of credit facility, amount outstanding	$ 55,000								0										$ 55,000	0
Notes Payable	5,351								7,700										5,351	7,700
Carrying Amount [Member] | 5% Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Senior notes	1,099,165								1,598,404										1,099,165	1,598,404
Carrying Amount [Member] | 4.5% Senior Notes due 2023 [Member]
Debt Instrument [Line Items]
Senior notes	1,491,339								1,488,960										1,491,339	1,488,960
Carrying Amount [Member] | 3.8% Senior Notes due 2024 [Member]
Debt Instrument [Line Items]
Senior notes	994,310								993,151										994,310	993,151
Carrying Amount [Member] | 4.375% Senior Notes Due 2028
Debt Instrument [Line Items]
Senior notes	989,661								988,617										989,661	988,617
Carrying Amount [Member] | 4.9% Senior Notes due 2044 [Member]
Debt Instrument [Line Items]
Senior notes	$ 691,688								$ 691,517										$ 691,688	$ 691,517
[1]	See Note 7. Long-Term Debt for discussion of the losses recognized by the Company upon the partial redemptions of its 2022 Notes in the 2019 third quarter and 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, 2019USD ($)
Senior Notes due 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 1,100,000
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, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Item Effected [Line Items]
Crude oil and natural gas sales																	$ 4,514,389	$ 4,678,722	$ 2,982,966
Gain (loss) on natural gas derivatives, net	$ (4,436)	[1]	$ 1,195	[1]	$ 53,448	[1]	$ (1,124)	[1]	$ (19,394)	[1]	$ (2,025)	[1]	$ (12,685)	[1]	$ 10,174	[1]	49,083	(23,930)	91,647
Crude oil and natural gas service operations																	68,475	54,794	46,215
Total revenues	1,195,134	[1]	1,104,197	[1]	1,208,382	[1]	1,124,234	[1]	1,149,294	[1]	1,282,151	[1]	1,137,113	[1]	1,141,028	[1]	4,631,947	4,709,586	3,120,828
Transportation expenses																	225,649	191,587	0
Net income (loss)	194,108	[2]	157,422		236,450		186,493		199,121		314,169		242,464		233,946		774,473	989,700	789,447
Net income (loss) attributable to Continental Resources	$ 193,946	[2]	$ 158,162		$ 236,557		$ 186,976		$ 197,738		$ 314,169		$ 242,464		$ 233,946		$ 775,641	988,317	$ 789,447
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 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)																		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 natural gas derivatives, net																		0
Crude oil and natural gas service operations																		0
Total revenues																		191,587
Transportation expenses																		191,587
Net income (loss)																		$ 0
[1]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
[2]	In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties and a $16.9 million ( $0.05 per basic and diluted share) decrease in income tax expense and corresponding increase in net income was recognized as discussed in Note 9. Income Taxes

Revenues Revenues Disaggregatio

Revenues Revenues Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Transportation expenses	$ 225,649	$ 191,587	$ 0
Crude oil and natural gas sales	4,514,389	4,678,722	$ 2,982,966
Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	4,514,389	4,678,722
Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0
North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,227,498	3,396,625
North Region [Member] | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,227,498	3,396,625
North Region [Member] | Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0
South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	1,286,891	1,282,097
South Region [Member] | Transferred at Point in Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	1,286,891	1,282,097
South Region [Member] | Transferred over Time
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	0	0
Crude oil sales
Disaggregation of Revenue [Line Items]
Transportation expenses	192,000	162,300
Crude oil and natural gas sales	3,929,994	3,792,594
Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,092,642	3,121,146
Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	837,352	671,448
Natural gas sales
Disaggregation of Revenue [Line Items]
Transportation expenses	33,700	29,300
Crude oil and natural gas sales	584,395	886,128
Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	134,856	275,479
Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	449,539	610,649
Operated properties | Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	3,152,226	2,933,781
Operated properties | Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	2,365,574	2,330,711
Operated properties | Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	786,652	603,070
Operated properties | Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	521,132	761,988
Operated properties | Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	109,668	214,741
Operated properties | Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	411,464	547,247
Non-operated properties | Crude oil sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	777,768	858,813
Non-operated properties | Crude oil sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	727,068	790,435
Non-operated properties | Crude oil sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	50,700	68,378
Non-operated properties | Natural gas sales
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	63,263	124,140
Non-operated properties | Natural gas sales | North Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	25,188	60,738
Non-operated properties | Natural gas sales | South Region [Member]
Disaggregation of Revenue [Line Items]
Crude oil and natural gas sales	$ 38,075	$ 63,402

Income Taxes - Provision for In

Income Taxes - Provision for Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Current federal income tax (provision) benefit	$ 0	$ (7,781)	$ (7,781)
Current tax (provision), various states	0	5	0
Total current income tax (benefit)	0	(7,776)	(7,781)
Deferred federal income tax (provision) benefit	191,328	282,947	81,054
Tax benefit from US tax reform legislation	0	0	(713,655)
Deferred tax (provision) benefit, various states	21,361	31,931	7,002
Total deferred income tax provision (benefit)	212,689	314,878	(625,599)
Provision (benefit) for income taxes	$ 212,689	$ 307,102	$ (633,380)
Effective tax rate	21.50%	23.70%	(405.80%)

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	$ 987,162	$ 1,296,802	$ 156,067
Expected income tax provision based on US statutory tax rate	207,304	272,328	54,623
State income taxes, net of federal benefit	31,967	45,920	4,682
Tax benefit from US tax reform legislation	0	0	(713,655)
Tax benefit (deficiency) from stock-based compensation	(7,971)	(259)	3,932
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Share-based Payment Arrangement, Amount	8,282	2,932	13,813
Sale of Canadian subsidiary and assets	(16,860)	0	0
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	19,600
Other, net	(10,033)	(13,819)	3,225
Provision (benefit) for income taxes	$ 212,689	$ 307,102	$ (633,380)
Federal statutory income tax rate	21.00%	21.00%	35.00%
Effective tax rate	21.50%	23.70%	(405.80%)

Income Taxes - Components of De

Income Taxes - Components of Deferred Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	$ 19,600
Deferred tax assets, Net operating loss carryforwards	550,086	$ 549,166
Deferred tax assets, Canadian net operating loss carryforwards	0	19,633
Deferred Tax Assets, Tax Deferred Expense, Compensation and Benefits, Share-based Compensation Cost	13,157	13,122
Deferred Tax Assets, Other	18,466	13,622
Total deferred tax assets	581,709	595,543
Deferred Tax Assets, Valuation Allowance	0	(19,633)
Deferred Tax Assets, Net	581,709	575,910
Deferred tax liabilities, Property and equipment	(2,367,137)	(2,144,767)
Deferred Tax Liabilities, Other	(1,697)	(5,579)
Total deferred tax liabilities	(2,368,834)	(2,150,346)
Net deferred tax liabilities	$ (1,787,125)	$ (1,574,436)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 3,300,000
Valuation Allowance, Deferred Tax Asset, Increase (Decrease), Amount	19,600
Deferred Tax Assets, Valuation Allowance	0	$ 19,633
UNITED STATES
Operating Loss Carryforwards [Line Items]
Federal Operating Loss Carryforwards	1,900,000
OKLAHOMA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	2,300,000
NORTH DAKOTA
Operating Loss Carryforwards [Line Items]
Net operating loss carryforwards, State	$ 872,000

Income Taxes Income Taxes - (De

Income Taxes Income Taxes - (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Tax benefit from US tax reform legislation	$ 0	$ 0	$ 713,655

Leases Description of leases (D

Leases Description of leases (Details) $ in Thousands	Dec. 31, 2019USD ($)
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 9,128
Drilling rig commitments [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	3,154
Surface use agreements [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	4,487
Field equipment [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	1,164
Other [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability	$ 323

Leases Leases additional inform

Leases Leases additional information (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Lease, Liability	$ 9,128
ASU 2016-02 Lease assets and liabilities recognition	19,000
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	1,208
Short-term Lease, Cost	176,586
Lease, Cost	199,646
Operating Lease, Cost	11,130
Variable Lease, Cost	11,930
Operating cash flows from operating leases	$ 804
Operating Lease, Weighted Average Remaining Lease Term	11 years 6 months
Weighted average discount rate	4.90%

Leases Leases, maturities of op

Leases Leases, maturities of operating leases (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 3,999
Lessee, Operating Lease, Liability, Payments, Due Year Two	750
Lessee, Operating Lease, Liability, Payments, Due Year Three	734
Lessee, Operating Lease, Liability, Payments, Due Year Four	667
Lessee, Operating Lease, Liability, Payments, Due Year Five	411
Lessee, Operating Lease, Liability, Payments, Due after Year Five	5,755
Lessee, Operating Lease, Liability, Payments, Due	12,316
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	3,188
Operating Lease, Liability	9,128
Current portion of operating lease liability	3,695	$ 0
Operating lease liabilities, net of current portion	$ 5,433	$ 0

Leases Leases (ASC 840), maturi

Leases Leases (ASC 840), maturities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 1,535
Operating Leases, Rent Expense, Net	2,000	$ 1,900
Operating Leases, Future Minimum Payments, Due in Two Years	1,042
Operating Leases, Future Minimum Payments, Due in Three Years	833
Operating Leases, Future Minimum Payments, Due in Four Years	805
Operating Leases, Future Minimum Payments, Due in Five Years	745
Operating Leases, Future Minimum Payments, Due Thereafter	6,795
Operating Leases, Future Minimum Payments Due	$ 11,755

Commitments and Contingencies -

Commitments and Contingencies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019USD ($)
Long-term Purchase Commitment [Line Items]
Future Drilling Commitments At Balance Sheet Date	$ 64,000
Purchase Obligation Agreement Expiration Date	2031
Future Drilling Commitments End Date	2020-11
Operating Lease, Liability	$ 9,128
Purchase Obligation	2,200,000
Purchase Obligation, Due in Next Twelve Months	291,000
Purchase Obligation, Due in Second Year	332,000
Purchase Obligation, Due in Third Year	330,000
Purchase Obligation, Due in Fourth Year	331,000
Purchase Obligation, Due in Fifth Year	298,000
Purchase Obligation, Due after Fifth Year	615,000
Drilling rig commitments [Member]
Long-term Purchase Commitment [Line Items]
Operating Lease, Liability	$ 3,154

Commitments and Contingencies L

Commitments and Contingencies Loss Contingencies (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Accrued litigation settlement	$ 0	$ 19,753
Legal proceedings recorded as a liability under other noncurrent liabilities	$ 8,700	4,700
Strack royalty payment litigation [Member]
Loss Contingencies [Line Items]
Accrued litigation settlement		$ 19,800	$ 59,600

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Amount charged to affiliate for aircraft use	$ 17,600	$ 12,900	$ 19,400
Amount charged to company by affiliate for aircraft use	303,000	598,000	460,000
Officers And Other Key Employees [Member]
Related Party Transaction [Line Items]
Revenues from transactions with related party	300,000	200,000	300,000
Due to affiliates	35,000	41,000
Revenues paid to related party	400,000	500,000	500,000
Due from affiliates	127,000	67,000
Other Affiliates [Member]
Related Party Transaction [Line Items]
Total amount paid to related party	426,000	529,000	368,000
Due to affiliates	38,000	161,000
Due from affiliates	1,400	2,700
Total amount received from related party	$ 18,900	$ 14,400	$ 18,600

Stock Based Compensation - Asso

Stock Based Compensation - Associated Compensation Expense (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement [Abstract]
Stock-based compensation	$ 52,044	$ 47,236	$ 45,868

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value at vesting date	$ 79.7	$ 61	$ 39.8
Unrecognized compensation expense related to non-vested	$ 66
Unrecognized compensation expense related to non-vested, period for recognition, in years	1 year 2 months 12 days
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	12,983,543
2013 Plan [Member] | Restricted stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock available to grant	13,036,804

Stock Based Compensation - Summ

Stock Based Compensation - Summary of Changes in Non Vested Shares of Restricted Stock (Detail) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	4,022,409	4,026,110	3,913,634
Granted shares	1,526,825	1,390,914	1,585,870
Vested shares	(1,737,304)	(1,116,329)	(874,665)
Forfeited shares	(350,022)	(278,286)	(598,729)
Non-vested shares, ending balance	3,461,908	4,022,409	4,026,110
Non-vested, weighted average grant-date fair value, beginning of period	$ 38.44	$ 35.63	$ 37.12
Granted, weighted average grant-date fair value	43.21	52.71	44.58
Vested, weighted average grant-date fair value	24.19	46.19	57.36
Forfeited, weighted average grant-date fair value	47.13	38.06	37.34
Non-vested, weighted average grant-date fair value, end of period	$ 46.82	$ 38.44	$ 35.63

Shareholders' Equity Attribut_3

Shareholders' Equity Attributable to Continental Resources (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive income		$ 0	$ 415	$ 307	$ (260)
Foreign currency translation adjustments		140	108	567
Release of cumulative translation adjustment	[1]	(555)	0	0
Translation Adjustment Functional to Reporting Currency, Tax Expense (Benefit)	[2]	0	0	0
Other Comprehensive Income (Loss), Net of Tax		$ (415)	$ 108	$ 567
[1]	In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 16. Property Dispositions
[2]	A valuation allowance had 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.

Shareholders' Equity Attribut_4

Shareholders' Equity Attributable to Continental Resources Share Repurchase Program (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	May 31, 2019
Share Repurchase Program [Abstract]
Stock Repurchase Program, Authorized Amount		$ 1,000
Stock Repurchased and Retired During Period, Shares	5,646,553
Treasury Stock, Retired, Cost Method, Amount	$ 190.2

Shareholders' Equity Attribut_5

Shareholders' Equity Attributable to Continental Resources Dividend (Details) - $ / shares	2 Months Ended	12 Months Ended
	Feb. 26, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.05
Common Stock, Dividends, Per Share, Cash Paid		$ 18,400,000
Subsequent Event [Member]
Subsequent Event [Line Items]
Common Stock, Dividends, Per Share, Declared	$ 0.05
Common Stock, Dividends, Per Share, Cash Paid	$ 18,400,000

Noncontrolling Interests (Detai

Noncontrolling Interests (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Noncontrolling Interest [Line Items]
Equity transaction costs		$ 0	$ 4,838	$ 0
TMRC II [Member]
Noncontrolling Interest [Line Items]
Proceeds from formation of new mineral relationship	$ 214,800
Other Noncontrolling Interests	266,800	356,900	266,800
SFPG, LLC [Member]
Noncontrolling Interest [Line Items]
Other Noncontrolling Interests	$ 9,900	$ 9,800	$ 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%

Property Dispositions - Additio

Property Dispositions - Additional Information (Detail) $ in Thousands

3 Months Ended

12 Months Ended

Dec. 31, 2019USD ($)

[1]

Sep. 30, 2019USD ($)

[1]

Jun. 30, 2019USD ($)

[1]

Mar. 31, 2019USD ($)

[1]

Dec. 31, 2018USD ($)

[1]

Sep. 30, 2018USD ($)

[1]

Jun. 30, 2018USD ($)

[1]

Mar. 31, 2018USD ($)

[1]

Dec. 31, 2019USD ($)

Dec. 31, 2018USD ($)

Dec. 31, 2017USD ($)aBoe

Property Acquisition And Dispositions [Line Items]

Proceeds from Sale of Oil and Gas Property and Equipment

$ 85,300

$ 54,500

Proceeds from sale of assets

88,734

54,458

$ 144,353

Gain (Loss) on Disposition of Property Plant Equipment

$ (1,182)

$ 535

$ 364

$ (252)

$ (8,410)

$ (1,510)

$ (6,710)

$ (41)

535

16,671

55,124

Release of cumulative translation adjustment

[2]

(555)

$ 0

0

CANADA

Property Acquisition And Dispositions [Line Items]

Proceeds from Sale of Oil and Gas Property and Equipment

1,700

Gain (Loss) on Disposition of Property Plant Equipment

(1,000)

Release of cumulative translation adjustment

$ (500)

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

Oil and Gas, Production Reserve, Energy | 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

[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.

[2]

In conjunction with the Company’s sale of its Canadian operations in 2019, the cumulative translation adjustments were released. See Note 16. Property 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	12 Months Ended
	Dec. 31, 2019		Dec. 31, 2018		Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Sale of Canadian subsidiary and assets	$ (16,860)		$ 0		$ 0
Tax benefit from US tax reform legislation	0		0		(713,655)
Crude oil and natural gas sales	4,514,389	[1]	4,678,722	[1]	2,982,966
Production expenses	(444,649)		(390,423)		(324,214)
Production taxes	(357,988)		(353,140)		(208,278)
Results of Operations, Transportation Costs	(225,649)		(191,587)		0
Exploration Expense	(14,667)		(7,642)		(12,393)
Depreciation, depletion, amortization and accretion	(1,997,854)		(1,839,241)		(1,652,180)
Property impairments	(86,202)		(125,210)		(237,370)
Income tax (provision) benefit (2)	(323,025)	[2]	(434,047)		504,475	[2]
Results from crude oil and natural gas producing activities	$ 1,064,355		$ 1,337,432		$ 1,053,006
[1]	For 2019 and 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 rules were prospectively applied beginning January 1, 2018 and prior period results were not 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 2019 and 2018 and a 38% combined tax rate for 2017 on pre-tax income generated by operations in the United States. Additionally, the 2019 period includes the $16.9 million income tax benefit recognized upon the Company's sale of its Canadian operations during the year. Further, the 2017 period includes the $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.

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Property Acquisition Costs - Proved	$ 51,558	$ 31,579	$ 8,446
Property Acquisition Costs - Unproved	312,680	329,586	220,875
Total property acquisition costs	364,238	361,165	229,321
Exploration Costs	50,143	81,015	123,461
Development Costs	2,388,582	2,478,327	1,695,954
Costs Incurred, Oil and Gas Property Acquisition, Exploration, and Development Activities	$ 2,802,963	$ 2,920,507	$ 2,048,736

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, 2019	Dec. 31, 2018	Dec. 31, 2017
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Development costs included in asset retirement costs	$ 6.7	$ 25.8	$ 15.3

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, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Proved crude oil and natural gas properties	$ 26,611,429	$ 24,060,625
Unproved crude oil and natural gas properties	319,592	291,564
Total	26,931,021	24,352,189
Less accumulated depreciation, depletion and amortization	(12,635,247)	(10,680,870)
Net capitalized costs	$ 14,295,774	$ 13,671,319

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, 2019USD ($)Well	Dec. 31, 2018USD ($)Well	Dec. 31, 2017USD ($)Well
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Balance at January 1	$ 3,959	$ 31,356	$ 34,852
Additions to capitalized exploratory well costs pending determination of proved reserves	28,280	45,088	79,451
Reclassification to proved crude oil and natural gas properties based on the determination of proved reserves	(23,200)	(72,347)	(81,035)
Capitalized exploratory well costs charged to expense	(2,782)	(138)	(1,912)
Balance at December 31	$ 6,257	$ 3,959	$ 31,356
Number of wells | Well	11	16	37

Supplemental Crude Oil and Na_3

Supplemental Crude Oil and Natural Gas Information - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2019MBoe	Dec. 31, 2019MMcf	Dec. 31, 2019MBbls	Dec. 31, 2019$ / Barrels	Dec. 31, 2019$ / Mcf	Dec. 31, 2018$ / McfMBoeMMcfMBbls	Dec. 31, 2017$ / McfMBoeMMcfMBbls
Reserve Quantities [Line Items]
Extensions, discoveries, and other additions		365,034					565,030	240,206
Discount factor utilized as standardized measure for future net cash flows	10.00%
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				(88,307)			(76,994)	(77,779)
Extensions, discoveries and other additions | MBbls				162,710			253,066	129,895
Weighted average price utilized in computation of future cash inflows | $ / Mcf						51.95	61.20	47.03
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			(363,239)				(1,153,555)	(25,390)
Extensions, discoveries and other additions | MMcf			1,213,947				1,871,777	661,867
Weighted average price utilized in computation of future cash inflows					2.02		3.22	3
Bakken [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			283	113
Extensions, discoveries, and other additions		160,000
SCOOP [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			830	47
Extensions, discoveries, and other additions		186,000
STACK [Member]
Reserve Quantities [Line Items]
Extensions, discoveries and other additions			101	2
Extensions, discoveries, and other additions		19,000
Change in development plans | Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		(35)					(234)	(89)
Change in development plans | Proved Undeveloped Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			(108)				(960)
Change in development plans | Proved Undeveloped Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				(17)			(74)
Price Driven | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		(43)					26	42
Price Driven | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			(118)				31
Price Driven | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				(24)			21
Economics, Performance and Other [Domain] | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			(278)				(216)
Economics, Performance and Other [Domain] | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				(38)			(21)
Other | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates		14					(4)	(5)
Other | Proved Reserves [Domain] | Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf			139				(11)
Other | Proved Reserves [Domain] | Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls				(9)			(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, 2019MBoeMMcfMBbls	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoe
Reserve Quantities [Line Items]
Proved Developed and Undeveloped Reserve, Net (Energy) | MBoe	1,619,265	1,522,365	1,330,995	1,274,864
Changes in Proved Reserves [Roll Forward]
Revisions of previous estimates | MBoe	(148,848)	(269,253)	(82,012)
Extensions, discoveries, and other additions | MBoe	365,034	565,030	240,206
Proved Developed and Undeveloped Reserve, Production (Energy) | MBoe	124,244	108,839	88,562
Sales of minerals in place, Total | MBoe	(1,840)	(8,011)	(15,197)
Purchases of minerals in place, Total | MBoe	6,798	12,443	1,696
Percent of proved crude oil reserve estimates prepared by external reserve engineers	91.00%	98.00%	96.00%
Natural Gas [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MMcf	4,591,614	4,140,281	3,789,818
Revisions of previous estimates | MMcf	(363,239)	(1,153,555)	(25,390)
Extensions, discoveries and other additions | MMcf	1,213,947	1,871,777	661,867
Production | MMcf	(311,865)	(284,730)	(228,159)
Sales of minerals in place | MMcf	(6,224)	(35,142)	(64,989)
Purchases of minerals in place | MMcf	30,238	52,983	7,134
Proved reserves at end of period | MMcf	5,154,471	4,591,614	4,140,281
Crude Oil [Member]
Changes in Proved Reserves [Roll Forward]
Proved reserves at beginning of period | MBbls	757,096	640,949	643,228
Revisions of previous estimates | MBbls	(88,307)	(76,994)	(77,779)
Extensions, discoveries and other additions | MBbls	162,710	253,066	129,895
Production | MBbls	(72,267)	(61,384)	(50,536)
Sales of minerals in place | MBbls	(803)	(2,154)	(4,365)
Purchases of minerals in place | MBbls	1,758	3,613	506
Proved reserves at end of period | MBbls	760,187	757,096	640,949

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, 2019MBoeMMcfMBbls	Dec. 31, 2018MBoeMMcfMBbls	Dec. 31, 2017MBoeMMcfMBbls	Dec. 31, 2016MBoeMMcfMBbls
Reserve Quantities [Line Items]
Proved Developed Reserves (MBOE)	707,424	675,206	601,901
Proved Undeveloped Reserve (MBOE)	911,841	847,159	729,094
Proved Developed and Undeveloped Reserve, Net (MBOE)	1,619,265	1,522,365	1,330,995	1,274,864
Crude Oil [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MBbls	88,307	76,994	77,779
Proved Developed Reserves (Volume) | MBbls	336,405	347,825	318,707
Proved Undeveloped Reserve (Volume) | MBbls	423,782	409,271	322,242
Proved Developed and Undeveloped Reserves, Net | MBbls	760,187	757,096	640,949	643,228
Natural Gas [Member]
Reserve Quantities [Line Items]
Revisions of previous estimates | MMcf	363,239	1,153,555	25,390
Proved Developed Reserves (Volume) | MMcf	2,226,117	1,964,289	1,699,161
Proved Undeveloped Reserve (Volume) | MMcf	2,928,354	2,627,325	2,441,120
Proved Developed and Undeveloped Reserves, Net | MMcf	5,154,471	4,591,614	4,140,281	3,789,818
Change in development plans | Proved Undeveloped Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates	35	234	89
Price Driven | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates	43	(26)	(42)
Other | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates	(14)	4	5
Instrument Type [Domain] | Proved Reserves [Domain]
Reserve Quantities [Line Items]
Revisions of previous estimates	85	57	30

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, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Supplemental Crude Oil and Natural Gas Information [Abstract]
Discount factor utilized as standardized measure for future net cash flows	10.00%
Future cash inflows	$ 49,893,470	$ 61,510,432	$ 42,574,897
Future production costs	(15,309,672)	(16,139,001)	(11,159,362)
Future development and abandonment costs	(10,033,887)	(9,706,114)	(6,487,097)
Future income taxes	(3,351,657)	(6,012,439)	(3,488,755)
Future net cash flows	21,198,254	29,652,878	21,439,683
10% annual discount for estimated timing of cash flows	(10,736,613)	(13,968,061)	(10,969,506)
Standardized measure of discounted future net cash flows	$ 10,461,641	$ 15,684,817	$ 10,470,177	$ 5,510,223

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, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 15,684,817	$ 10,470,177	$ 5,510,223
Extensions, discoveries and improved recoveries, less related costs	1,649,322	5,162,635	1,462,629
Revisions of previous quantity estimates	(1,564,503)	(3,522,428)	(1,004,355)
Changes in estimated future development and abandonment costs	1,401,513	1,063,089	743,657
Increase Due to Purchases of Minerals in Place	49,330
Sales of Minerals in Place		(9,192)	(41,077)
Net change in prices and production costs	(6,591,347)	4,224,473	3,808,116
Accretion of discount	1,865,034	1,183,347	665,507
Sales of crude oil and natural gas produced, net of production costs	(3,486,103)	(3,743,572)	(2,450,474)
Development costs incurred during the period	1,557,121	1,134,153	1,045,875
Change in timing of estimated future production and other	(1,690,779)	1,324,365	948,519
Change in income taxes	1,587,236	(1,602,230)	(218,443)
Net change	(5,223,176)	5,214,640	4,959,954
Standardized measure of discounted future net cash flows at end of year	$ 10,461,641	$ 15,684,817	$ 10,470,177

Quarterly Financial Data - Sche

Quarterly Financial Data - Schedule Of Quarterly Financial Data (Detail) - USD ($)	3 Months Ended																12 Months Ended
	Dec. 31, 2019		Sep. 30, 2019		Jun. 30, 2019		Mar. 31, 2019		Dec. 31, 2018		Sep. 30, 2018		Jun. 30, 2018		Mar. 31, 2018		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Effect of Fourth Quarter Events [Line Items]
Sale of Canadian subsidiary and assets																	$ (16,860,000)	$ 0	$ 0
Estimated litigation liability, after tax																			$ 37,000,000
Diluted eps estimated litigation settlement																			$ 0.10
Diluted EPS impact from sale of Canadian assets	$ 0.05
Loss on extinguishment of debt	0	[1]	$ 4,584,000	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 7,133,000	[1]	$ 0	[1]	$ 0	[1]	4,584,000	7,133,000	$ 554,000
Net income (loss)	194,108,000	[2]	157,422,000		236,450,000		186,493,000		199,121,000		314,169,000		242,464,000		233,946,000		774,473,000	989,700,000	789,447,000
Total revenues	1,195,134,000	[3]	1,104,197,000	[3]	1,208,382,000	[3]	1,124,234,000	[3]	1,149,294,000	[3]	1,282,151,000	[3]	1,137,113,000	[3]	1,141,028,000	[3]	4,631,947,000	4,709,586,000	3,120,828,000
Gain (loss) on derivative instruments, net	4,436,000	[3]	(1,195,000)	[3]	(53,448,000)	[3]	1,124,000	[3]	19,394,000	[3]	2,025,000	[3]	12,685,000	[3]	(10,174,000)	[3]	(49,083,000)	23,930,000	(91,647,000)
Property impairments	19,348,000	[4]	20,199,000	[4]	21,339,000	[4]	25,316,000	[4]	38,494,000	[4]	23,770,000	[4]	29,162,000	[4]	33,784,000	[4]	86,202,000	125,210,000	237,370,000
Litigation settlement																	0	0	59,600,000
Gain (Loss) on Disposition of Property Plant Equipment	1,182,000	[5]	(535,000)	[5]	(364,000)	[5]	252,000	[5]	8,410,000	[5]	1,510,000	[5]	6,710,000	[5]	41,000	[5]	(535,000)	(16,671,000)	(55,124,000)
Income from operations	293,876,000		278,724,000		379,847,000		304,965,000		330,414,000		491,308,000		391,276,000		380,722,000		1,257,412,000	1,593,720,000	449,401,000
Tax benefit from US tax reform legislation																	0	0	(713,655,000)
Net income (loss) attributable to Continental Resources	$ 193,946,000	[2]	$ 158,162,000		$ 236,557,000		$ 186,976,000		$ 197,738,000		$ 314,169,000		$ 242,464,000		$ 233,946,000		$ 775,641,000	$ 988,317,000	$ 789,447,000
Net income per share: Basic	$ 0.53	[2]	$ 0.43		$ 0.63		$ 0.50		$ 0.53		$ 0.84		$ 0.65		$ 0.63		$ 2.09	$ 2.66	$ 2.13
Net income per share: Diluted	$ 0.53	[2]	$ 0.43		$ 0.63		$ 0.50		$ 0.53		$ 0.84		$ 0.65		$ 0.63		$ 2.08	$ 2.64	$ 2.11
[1]	See Note 7. Long-Term Debt for discussion of the losses recognized by the Company upon the partial redemptions of its 2022 Notes in the 2019 third quarter and 2018 third quarter.
[2]	In the fourth quarter of 2019, the Company sold its Canadian subsidiary and associated properties and a $16.9 million ( $0.05 per basic and diluted share) decrease in income tax expense and corresponding increase in net income was recognized as discussed in Note 9. Income Taxes
[3]	Gains and losses on natural gas derivative instruments are reflected in “Total revenues” on both the consolidated statements of comprehensive income and this table of unaudited quarterly financial data. Commodity price fluctuations each quarter can result in significant swings in mark-to-market gains and losses, which affects comparability between periods.
[4]	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.
[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.